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A thermodynamic analysis of several pressurized fluidized bed combined cycle power generation systems Anastasiou, Roger 1983

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A THERMODYNAMIC A N A L Y S I S OF S E V E R A L P R E S S U R I Z E D F L U I D I Z E D COMBINED C Y C L E POWER G E N E R A T I O N S Y S T E M S  by  ROGER B.A.Sc.,University  A THESIS  ANASTASIOU Of  SUBMITTED  British  Columbia,  IN PARTIAL  T H E REQUIREMENTS  FULFILMENT  FOR T H E D E G R E E OF  M.A.SC.  in T H E F A C U L T Y OF G R A D U A T E S T U D I E S Department  Of  We a c c e p t to  Mechanical  this  thesis  th&^required  THE U N I V E R S I T Y  Roger  as  conforming  standard  OF B R I T I S H  October  ©  Engineering  COLUMBIA  1983  Anastasiou,  1983  1979  OF  BED  In  presenting  requirements  for  Columbia,  I  available  for  permission  this an  agree  for  thesis advanced  and  study.  I  granted  this  without  Department  of  by  thesis  my w r i t t e n  Mechanical  The U n i v e r s i t y of B r i t i s h 2075 Wesbrook P l a c e Vancouver, Canada V 6 T 1W5  Date:  September  20  1983  copying the It for  Head is  further thesis  of  my D e p a r t m e n t  understood  Engineering  gain  the  of  British  it  freely  agree  this  permission.  Columbia  make  of  financial  of  University  reference  representatives.  allowed  the  shall  or  of  at  Library  may  publication  degree  fulfilment  the  purposes her  partial  that  extensive  be  in  for  that  that  scholarly  or  by  copying  shall  not  his or be  i i  Abstract  This two  thesis  classes  of  presents  combined  the  cycle  power  cycles  have  been  proposed  for  future  their  cost  effectiveness  and  low  air  heater  cycle  are  system  which  will  the  Hat  tube  intercooled more  air  when from  air  coal.  while  to  cycles the  is  has  The was  50%  load,  30.8%.  on  an  also  The of  is  tube  found is  to  be  fired  is  steam to  of tube a  basis.  be  power  are  modelled  beneficial  to The  points  plants.  similar  simulation  thermal  of  develop  2 percentage  completed, gross  heater  detrimental.  efficiency load  coal  performance  cycle to  air  of  because  the  equal  bed,  and  stations  an  steam  coal  the  tube  modelling  found  part  plant  at  power  recuperation  cycle  cycle  cycle. heater  of  steam  in  modelling  fluidized  pollution.  emphasis the  computer  variations  conventional  heater  The  Intercooling  tube  than  operating 36.8%  compare  steam  conventional module,  The  cycle,  efficient The  seven  configurations  Creek  steam  systems.  and  simulated.  Several using  cycle  of  pressurized  fired  the  generation  results  of  to a  the  single  indicating  that  efficiency  drops  Table  of  Contents  Abstract L i s t of T a b l e s L i s t of F i g u r e s Acknowledgements Nomenclature I. INTRODUCTION 1.1 P r e s s u r i z e d F l u i d i z e d Bed Power G e n e r a t i o n 1.2 D e s c r i p t i o n O f P F B C o m b i n e d C y c l e s II. R E V I E W OF P R E V I O U S WORK AND STUDY O B J E C T I V E S 2.1 S t a t u s Of I n d u s t r i a l Research 2 . 2 R e v i e w Of P u b l i s h e d M o d e l s A n d A n a l y s e s 2 . 3 O b j e c t i v e s And Scope Of S t u d y III. D E S I G N LOAD C Y C L E S I M U L A T I O N MODELS 3.1 M o d e l l i n g S t r a t e g i e s 3.2 D e v e l o p m e n t Of The S u b - m o d e l s 3.2.1 Thermodynamic P r o p e r t y C a l c u l a t i o n s 3.2.2 C o m b u s t i o n Of C o a l I n A F l u i d i z e d Bed 3.2.3 Heat E x c h a n g e r s And E f f e c t i v e n e s s 3.2.4 Turbomachinery 3.2.5 N e t E f f i c i e n c y And A u x i l i a r y Power L o s s e s IV. D E S I G N LOAD C Y C L E A N A L Y S I S R E S U L T S 4.1 S t e a m T u b e PFB C y c l e R e s u l t s 4.1.1 Steam Tube C y c l e V a r i a t i o n s 4.1.2 I n t e r c o o l e d Steam Tube C y c l e R e s u l t s 4.2 A i r H e a t e r C y c l e A n a l y s i s R e s u l t s 4 . 3 E f f e c t O f F u e l C o m p o s i t i o n On C y c l e P e r f o r m a n c e 4 . 4 C o m p a r i s o n Of C y c l e R e s u l t s V. PART LOAD M O D E L L I N G OF T H E A I R H E A T E R C Y C L E 5.1 M o d e l l i n g S t r a t e g i e s A n d C o n s i d e r a t i o n s 5.1.1 Transport Properties And Heat Transfer Coefficients 5.2 P a r t Load R e s u l t s VI. CONCLUSIONS 6.1 A r e a s F o r F u r t h e r Work BIBLIOGRAPHY APPENDIX A APPENDIX B APPENDIX C APPENDIX D APPENDIX E APPENDIX F APPENDIX G APPENDIX H APPENDIX I -  i i iv v vii viii 1 1 5 7 7 13 14 16 16 21 21 24 31 34 ....36 37 37 38 41 43 ...45 46 47 47 53 56 58 59  61 COMPUTER S U B R O U T I N E S 108 THERMODYNAMIC AND T R A N S P O R T P R O P E R T I E S 112 COMBUSTION C A L C U L A T I O N S 118 COMPONENT PERFORMANCE F O R M U L A T I O N S AND DATA 129 STEAM TUBE C Y C L E R E S U L T S 134 AIR HEATER CYCLE RESULTS 138 P U L V E R I Z E D COAL B O I L E R A N A L Y S I S R E S U L T S . . . . 1 4 4 GAS TURBOMACHINE C H A R A C T E R I S T I C EQUATIONS ..146 COMPUTER PROGRAMS 147  iv  List  of  Tables  1. 2. 3. 4. 5.  Published Cycle Analysis Results E q u i l i b r i u m D i s s o c i a t i o n Product Concentrations A n d e r s o n C r e e k L i m e s t o n e S u l p h u r R e t e n t i o n (13) Steam Tube C y c l e P e r f o r m a n c e C r i t e r i a E f f e c t o f C o a l T y p e on PFB C o m b i n e d C y c l e Performance  6.  Comparison  of  Power  Generation  Efficiencies  64 65 65 66 67 67  V  List  of Figures  1. R a n k i n e C y c l e 2. B r a y t o n C y c l e 3. T e m p e r a t u r e / E n t r o p y D i a g r a m s f o r t h e B r a y t o n a n d .Rankine C y c l e s 4. O i l F i r e d C o m b i n e d C y c l e P l a n t S c h e m a t i c 5. P r e s s u r i z e d F l u i d i z e d B e d C o a l C o m b u s t o r 6. A i r H e a t e r P F B C o m b i n e d C y c l e 7. S t e a m T u b e P F B C o m b i n e d C y c l e 8. S t e a m T u b e C y c l e w i t h I n t e r c o o l i n g 9. S t e a m T u b e C y c l e A n a l y s i s F l o w C h a r t 10. A i r H e a t e r C y c l e A n a l y s i s F l o w C h a r t 11. B o i l i n g P i n c h P o i n t i n a H e a t R e c o v e r y S t e a m Generator 12.. S t e a m  13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33.  Tube  Cycle  with  Double  Intercooling  68 69 70 71 72 73 74 75 76 78 80 81  Steam Tube C y c l e w i t h R e c u p e r a t i o n .....82 S t e a m T u b e C y c l e w i t h One F e e d W a t e r H e a t e r 83 E f f i c i e n c y o f t h e B a s i c Steam Tube C y c l e 84 E f f e c t o f I n t e r c o o l i n g on Steam Tube C y c l e Performance 85 E f f e c t o f R e c u p e r a t i o n on Steam Tube C y c l e Performance 86 E f f e c t o f F e e d Water H e a t i n g on Steam Tube C y c l e Performance 87 I n t e r c o o l e d Steam Tube C y c l e P e r f o r m a n c e 88 E f f e c t o f T u r b o m a c h i n e E f f i c i e n c y on t h e I n t e r c o o l e d Steam Tube C y c l e 89 E f f e c t o f I n t e r c o o l e r E f f i c i e n c y on t h e I n t e r c o o l e d Steam Tube C y c l e ...89 E f f e c t o f B o i l e r P r e s s u r e on t h e I n t e r c o o l e d Steam Tube C y c l e 90 E f f e c t o f Steam S u p e r h e a t on t h e I n t e r c o o l e d Steam Tube C y c l e 90 E f f e c t o f Steam R e h e a t on t h e I n t e r c o o l e d Steam Tube Cycle 91 E f f e c t o f A m b i e n t T e m p e r a t u r e on t h e I n t e r c o o l e d Steam Tube C y c l e 91 E f f e c t o f A m b i e n t P r e s s u r e on t h e I n t e r c o o l e d S t e a m Tube C y c l e 92 E f f e c t o f C o n d e n s e r T e m p e r a t u r e on t h e I n t e r c o o l e d Steam Tube C y c l e 92 E f f e c t o f E x c e s s A i r on t h e I n t e r c o o l e d S t e a m Tube Cycle 93 A i rHeater Cycle Performance 94 E f f e c t o f Gas T u r b o m a c h i n e E f f i c i e n c y on A i r H e a t e r Cycle Performance 95 E f f e c t o f Steam T u r b i n e E f f i c i e n c y on t h e A i r H e a t e r Cycle 96 E f f e c t o f C o n d e n s e r T e m p e r a t u r e on t h e A i r H e a t e r Cycle 96 Comparison of Cycle Performance with Three D i f f e r e n t  vi  34. 35. 36. 37. 38. 39. 40. 41. 42.  Fuels E f f e c t o f M o i s t u r e C o n t e n t I n C o a l On C y c l e Efficiency E f f e c t o f A s h C o n t e n t on C y c l e E f f i c i e n c y A x i a l C o m p r e s s o r P e r f o r m a n c e Map 1 A x i a l C o m p r e s s o r P e r f o r m a n c e Map 2 T u r b i n e P e r f o r m a n c e Map 1 T u r b i n e P e r f o r m a n c e Map 2 A i r Heater C y c l e P a r t Load C y c l e A n a l y s i s Flow Chart Part Load Performance of A i r Heater C y c l e V a r i a t i o n o f S t a c k G a s T e m p e r a t u r e a n d Dew P o i n t W i t h Load  97 98 98 99 100 101 102 103 106 107  vii  Acknowledgement  The  author  gratitude  wishes  to  encouragement  to  express  Professor  and  valuable  R.L.  his  sincere  Evans  direction  for  his  throughout  this  study. Thanks J.R.  Grace,  and  Dr.  advice. Columbia  are and  also  at  Support  acknowledged.  to  Professors  E . G . Hauptmann and  M. Papic  Hydro  due  and  B.C.  for  Hydro  this  Power  to  Hill,  M r . R.W. Woodley  for  research Authority  P.G.  their  helpful  from  British  is  gratefully  VI 1 1  Nomenclature  General  Symbols  Cp H h h Hfo Hf Hg k M M m M* N N* Nu P P Pr Re R Sf Sg S s T U Wp X u 77 p Z  Specific Heat Enthalpy E n t h a l p y (mole b a s i s ) F l u i d Heat T r a n s f e r Coefficient Heat of F o r m a t i o n Saturated Liquid Enthalpy S a t u r a t e d Vapour Enthalpy Thermal C o n d u c t i v i t y Mass Flow M o l e c u l a r Weight Mass Reduced Mass Flow Shaft Speed Reduced Speed N u s s e l t Number Pressure Pressure Ratio P r a n d t l Number R e y n o l d s Number Gas C o n s t a n t Saturated L i q u i d Entropy S a t u r a t e d Vapour Entropy Entropy E n t r o p y (mole b a s i s ) Temperature O v e r a l l Heat T r a n s f e r Coeff. Pumping Power Steam Q u a l i t y Viscosity Isentropic Efficiency Density A i r Fuel ratio  Subscripts: d o 0 1 2 m  Design Value Inlet Conditions Standard Conditions Fluid 1 Fluid 2 Mixture  kJ/kg°C kJ/kg kJ/kmole kJ/(s-m2K) kJ/kmole kJ/kg kJ/kg kw/(m.°C) kg/s  MPa  kJ/(kmole• kJ/kg°C kJ/kg°C kJ/kg°C kJ/kmole°C °C or K kJ/(s-m2K) kJ/s kg/(m-s) kg/m3  1  I .  1.1  Pressurized  F l u i d i z e d Bed  Pressurized combined  decade,  affords  efficiency  expensive  shift  in  the  nations. the  fluidized  cycles  generation  and  fuels,  in to  renewed  Constrained  by  the  maintain In coal  facilities  generating (Figure pressure and  and coal SOx,  increase  thus  combustion NOx, and  available require  fly  which  power  to  coal  government both  cost  fired and  power  burned  a  in  or  overall  systems ash  are  heating  generate  of  major  particulates.  of  are  specific  cost a  to  steam  performance  the  on  led  to  generation. new  and  power  able  facilities,  pulverized  the  and  western  transportation  power  generation  To enhance  efficiency  a  to  levels.  Rankine  water  for  regulations,  used  feed  caused  has  competitive  emission  past  possible,  This  fired  high  the  most  where  alcohol  in  In  of  resources.  with  combining  supplies  priorities  are  the  decrease  oil  turbines  regenerative  These  be  through  Steam  steam.  coal  ground  power  1).  must  pollutant  conventional finely  and  of  emissions.  foreign  and  interest  generation  opportunity  concentrated,  gas  economy  acceptable  is  has  natural  power  low p o l l u t a n t  domestic  and  generation  unique  generation  of  Generation  (PFB)  unreliable  research  development  Power  bed  a  with  power  Recent  developments  INTRODUCTION  coal  the  of  electricity. source  of  Systems  reduce  the  emissions  operate  and  thus  of  reduce  high  reheat  employed. the  cycle,  Conventional  three are  cycle  from  cycle,  commonly  work  boilers,  turbine power  the  pollutants: commercially  each  pollutant,  the  overall  but plant  2  efficiency. pollution  Pulverized  controls  coal  typically  power  have  plants  thermal  with  adequate  efficiencies  around  36%. Another or  Brayton  working air  is  system  cycle  fluid  added  and  through  either in  temperature  of  average is  the  gas  steam  it  is  addition  turbine  turbine  cycle,  cycles  the  systems  Brayton  cycle  turbine  gas  water.  This  is  cycles  to  achieve  higher  the  To  the  the  Fresh  4  and  15  or  oil)  is  expanded  a  efficiencies the  highest  the while  average minimizing  combined  cycles  temperature  of  condenser  temperature  of  The  heat  In  in  combustion  low  the  together  cycle,  transfer to  gas  provide  maximized  high  3).  exhaust  reduces  be  the  the  as  cycle.  then  Brayton  rejection.  with  used  between  are  turbine,  power.  must  (Figure  Rankine  gases  gas  is  natural  generation  heat  air  usually  itself.  combining  between  feed  by  heat  the  the  and  possible  of  in  (usually  Rankine  power  by  as  is  system,  combustion  any  achieved  this  generate  cycle  temperature  generation  pressure,  fuel  to  the  In  steam  high  the  both  cycle",  with  this  of  a  turbine  using  efficiency  the  to  where  gas  "combined than  instead  power  2).  b u r n e d . " The hot  a  By  in  (Figure  compressed  atmospheres,  used  important of  waste  Rankine  interaction heat  cycle  rejection  from  the  boiler  or  temperature  of  the  operation  in  system. There  Europe,  some c o m b i n e d c y c l e  achieving  relatively technical  are  clean  thermal  fuels  difficulties  such  power  efficiencies as  oil  associated  and with  plants up  to  natural coal  in  41%. gas,  These avoiding  combustion  in  burn the gas  3  turbines. cycle  The  most  w i t h a heat  common  recovery  system  steam  turbine  operates  as  power  generated  by t h e s t e a m  is The  most  direct  amount  therefore gases, for  being  mostly  use  removed  adequately the  excessive  development  methanol  of  are  generation  coal  also  fuel  the  are  flowing made  coal  upwards.  up m a i n l y  reduce reacts  to  of  sulphur with  sulphate) temperature  the which  the  is  being  coal  gas,  but these  due t o  their  In  high  usually  carbonate,  added  c a n be d i s c a r d e d  a  is  easily.  and the sorbent  is  the  not  been  barrier  generation.  liquid  fuels,  unlikely  and power  costs. c a n be u s e d bed  or to  the the  residue  Depending  if  systems, by a i r  limestone,  burned,  solid  are  remove  "fluidized",  dolomite is  an  gas  serious  coal  or  As the c o a l form  a  fluidized  suspended,  in  flue  has  are  of  by  considered  power  natural  is  i n the gases  gases  represents  pollution.  to  additional  low a n d medium BTU  sulphur  combustion  emissions.  and pressure  of  developed,  sorbent  to  to  A sorbent,  gas  methods  required  are  The  results  technology  direct  turbine  coal  for  synthetic  calcium  from  the need  gasified  particles  and  indirect  monoxide,  and t h i s  reduce  4).  eliminating  alternatives  taken  burning  to  heat  coal  The  cooling  of  being  Alternatively, steps  the  cycle  this  Various  generation.  demonstrated,  Conversion  deriving  however,  and carbon  However,  the gas  (Figure  Brayton  Gasifying  to combustion  without  of  pollution.  pursued.  power  prior  sulphur  of  is  turbine.  Often  hydrogen  in  scrubbing.  to  method  combustion.  undesirable  generator  in the simple  efficient  i n use  bed  and to  sulphur (calcium  on t h e b e d  characteristics,  up  to  4  95%  of the coal  (1). the the  Heat bed  bound  s u l p h u r c a n be  i s removed  (Figure  bed c o o l i n g Fluidized  from  5).  NOx  steam  are  as atmospheric  known  beds  are  to that  Several  groups  efficiency,  the  the  for conventional  of  combined  fluidized and  gases  as  approaches  the  tube  directly bed.  in  much  t o t h e steam  gases.  The  similar  to  gas  heater cycle,  the  turbine  system  within  is  resulting  air  standard  taken  steam  the steam gases  Brayton have  the from  system  and i s  heat  the higher In  combined  the place by  the  a  Two  proposed.  In  i s transferred fluidized exhaust  are  installations.  very  In t h e  a l l of i t s heat waste  of hot  cycle.  conditions  receives  the  facilities.  the gas t u r b i n e  steam  thus  been  systems  systems i s  pressurized  superheat  in conventional  exhaust  driven  of the combustion  system  heat  those  the  coal  and t a k e s  is  to  because  bed systems.  turbine  t o t h e steam  cycle,  Additional  fluidized  of  past  These  investigating  bed i s p r e s s u r i z e d  the  different steam  cycle  the  of these  pulverized been  in  beds  The p e r f o r m a n c e  have  submerged i n  low b e c a u s e  cycles.  fluidized  conventional  technique  temperatures.  used  Rankine  pressure  however,  combustor,  combustion  been  this  tubes very  low c o m b u s t i o n have  not p r e s s u r i z e d .  similar  cycles  emissions are also  boilers  generate  with  t h e b e d by c o o l i n g  and r e s u l t i n g bed  removed  heat  from  recovery  system. Development technical  of  difficulties.  and  corrosion  much  e x p e r i m e n t a l work  PFB  facilities  The main  of gas t u r b i n e  has  problem  been  has been  slow the  b l a d e s by h o t c o m b u s t i o n  h a s been  done  to  develop  due  to  erosion  gases and  systems  which  5  provide of  a  reasonable  upgrading  reducing reduced  the  decrease  cost  technology.  1.2  Description  this  6)  is  air  study.  is  air  is  used  pressurized  to cool  enter  a  used  to  drive  a  An  steam  generated coming  particulate the gas  in  from  appealing loading entering  to  Wright  in a  t h e steam  aspect  of  achieved the turbine  This  and  substantially being  combined  offset  design  done.  cycles  is  a  a  dramatic  results  the  cost  in of  air  are  a the  (2).  In of  i n the PFB. of  gas  recovery  the  cycle,  compressed  steam  is  recombined and  exhaust  Approximately  gas  this  (Figure  The remainder  are  i n the turbine heat  investigated  Combined C y c l e  One t h i r d  turbine. the  of  gases  s t i l l  PFB s y s t e m s  7 atm.  heat  is  approach  Cycles  T h e two s t r e a m s  steam  have  plant.  helps  the  the combustor  the A i r Heater  about  Residual  low p r e s s u r e is  the  combustion  the bed.  produce  of  combined c y c l e  to  as  turbine.  remainder  of  used  filtering  efficiency  which  The f i r s t ,  The combined  temperature  Of PFB C o m b i n e d  of  life.  much r e s e a r c h  of  on t h e C u r t i s s  then  power  size  saving  classes  based  although increased  the  new  Two  inlet  from p r e s s u r i z a t i o n  in  significant  the  blade  materials,  turbine  with  benefit  in  blade  the problem,  Along major  the  turbine  gases  is  generator  and  60%  turbine/compressor,  of  the  with  the  turbine. this  design  i n t h e gas is  clean  is  turbine. air,  the  reduced  Because  the gases  do  much not  6  have  to  be  filtered  to  the  fine  degree  required  i n o t h e r PFB  systems. The  second  American  Electric  National  Coal  variations  is  t h e Steam  Power,  Board  of  water(1,5). among  cycle  of  this  Stal  The c o m b u s t i o n  three  PFBs,  reheating  the  filtered  t o meet  one  steam.  exhaust  gases  are  steam  system  Laval,  Great  design  which air  the turbine  is  The  with  from  turbine  and the l a c k  by  the  including  air  heater  feedwater  boiling,  the exception of  and steam  heaters,  the  hot  tube  gases  similar  economiser  and -are  the to heat  heaters.  cycles  recuperators,  distributed  The t u r b i n e  is  the  feedwater  boiling  preheating  system of  and the  superheating  specifications.  steam  plants,  Both  and  7).  developing  the bed with  an e c o n o m i s e r ,  conventional t h e gas  been  pressurized  inlet  (Figure  Electric,  have  combustion,  through  feedwater.  General  cools  for  After  PFB s y s t e m  Britain  each  passed  Tube  c a n be  and  modified  intercooling.  7  II.  REVIEW OF P R E V I O U S  Status  2.1  In  the  agencies the  new  areas hot  the  past  in  of  research cleanup  modelled  the  by  economically air  heater  of  the  already Also,  the  than  the  steam  by  cycles. units  in was  gas  Finally, is  Energy  limited,  to  pilot of  and  government  been  developing  generation.  The main  durability,  arrangements Brief  research  have  and also  descriptions  groups  an  design,  of  follow.  a  for  is  cycle.  Secondly, than  because several  the  several  to  the  their size  in  estimates of  independent  the  to  system  The most have  facilities.  air  heater  result  cycle  in  lower  system  efficiency  for  steam  the  individual  units  was  Firstly,  will  heater  operate  manner.  heater  the  by  electricity  industrial  factors  air  produce  air  in  and plant  reasons.  much e a s i e r These  sponsored  acceptable  the  proven  The  (2).  system  for  been  construct,  environmentally  required  higher  (C-W) h a s  plant  such  chosen  tube  C-W i s  have  material  cycle  Corporation  cleanup  costs.  transfer,  Various  technologically  hot  development claimed  of  components been  PFB power  important  ability  cycle  for  States  i n d i v i d u a l groups.  PFB  and  companies  United  heat  Wright  cycle the  of  Corporation  Department  demonstrate  in  within  Wright  combined  the  necessary  the  Curtiss  U.S.  number  equipment.  developments  The  a  and  are  OBJECTIVES  Research  decade,  Europe  Curtiss  a  Industrial  technology  gas  been  Of  WORK AND STUDY  will  be  gas  tube  turbine  required  to  8  make  up a  approach A  utility results  15  operation  MW by  and  from  1/3  of  C-W  of  plant  in an  turbine  the  bed  the  selection  concentrations  scale  gas  be  required.  turbine and  cleanup  Tests  blades.  blade  lives  of  greater  General  Electric  General  Electric  high  bed  pressure represent higher  (10  Bar)  the  temperatures  and of  erosion  an  life. 4  have  performed  materials than  tube for  many  has  925  and  begin  to  done,  which  will  turbine  inlet small  be  will of  suitable  expected.  investigating  These  soften  a  cleanup  to  965°C  fluidized  heat  durability  are  (1).  cleanup  also  gas  proven  been  1/4  performed  using  the  hours  be  maximum  alloy  on  (GE)  cycle  were  were  further  have  25,000  normal  coals  tests  achieved  some  gaseous  gas  Acceptable  been  in  thermal  will  hot  for  economical  be  requirements.  Experiments  configuration  (between  steam  limit  wear.  will  NOx e f f l u x  design,  Corporation  temperature  EPA  the bed tube  also  Several  and  and  predicted  limits.  assembly.  were  The below  SOx  modular  forecasting  regulatory  tube  particulate  C-W i s  well  fin  corrosion  construction  and  the  This  performance.  40%.  blade  tube  station.  load  under  (2)  coal,  acceptable  hot  is  are  respective  Hot  resulting  part  1983  sulphur  and  transfer.  provide  plant  has i n v e s t i g a t e d  determine  generating  approximately  their  equipment, to  end  the  3.1%  power  efficient  pilot  of  emissions Burning  in  the  efficiency  size  bed and  ),  medium  a bed  temperatures operation. the  At  particles  9  adhere  to  each  questionable erosion  whether  has  been  They  found  gases  standard  turbine  several  new  alloys  hours.  They  Leatherhead transfer  c a n be  were  that  blade  on  to  have in  development systems  for  resulting blades.  of  the  concentrations  turbine  steam  tube  the  PFB  in  the  successful  use  (3).  GE  has  tested  working  also  turbine  is  prevent  materials is  It  and the  by t h e  the  cleanup  enough  and  facility  temperatures  the a l k a l i  high  fluidization.  tolerated  and h o t gas  exhaust  25,000  high  concentrating  materials  systems.  preventing  the  and c o r r o s i o n  GE blade  other,  toward  sponsored  England  to  a  thus  turbine  tests  determine  at  life the  of  of NCB  bed-side  heat  coefficients.  Stal-Laval,  American E l e c t r i c  Power,  Deutsche  Babcock  Anlagen Stal-Laval Power  Service  Britain first  Turbin  AB ( S - L )  Corporation  combined  commercial  their size  expertise PFB power  Babcock  and  the  German c o m p a n y ,  West  Wilcox  objective  of  Brilliant,  Ohio  combustion divided  the  left  Sweden,  is  plant)  in  1976 t o  generation  and  three  to  modify  to  include  h o t gas  parties. cleanup  and Wilcox design  of  been  the  then,  (DBA).  power  the p r o j e c t  equipment.  Great  replaced  combined  S-L w i l l  of  Since  Anlagen a  Electric  and b u i l d  plant.  and has  Babcock  The r e s p o n s i b i l i t i e s the  the American  and Babcock  the group  Deutche  project  up between  turbomachinery  has  (the Tidd  (4).  (AEP),  of  supply  by The  plant  in  cycle  PFB  have  been  the  gas  DBA w i l l  design  1 0  and  construct  erected  and  interest  in  the  because  of  its  high  cycle  an  efficiency  turbine  overall plants below  of  is of  and  projected  S-L  to  40  an  improved  be  year  39.4% of  by  the  of  feed  have  systems  results.  Tests  bed  heat  to  provide  plant.  erosion  a  in  for  the  Tidd  and  low  turbine  its  temperature the  of  the a the  to  a  cleanup will  be The  low  steam  modern  steam  efficiency  reduction  compared  in  operation.  With  are  gas  efficiency  8%  used  results  hot  plant  an  in  is the  new c o n v e n t i o n a l  expected  to  development  to  PFB,  been  and  design  of  subsystems  the  and  hot  gas  tested  completed  corrosion.  operating has  program  provide  Prototype  also  satisfactory  including  be  Bar)  arrangement,  constructed  have  exchanger  will  be  because  and  feasibility  been  this  be  well  has  been  limits.  consortium  the  controlling  will  old  when  be  turbine  Tidd.plant  emissions  research  the  construction  result  the  will  gas  turbine.  cycle  have  completed,  reduces  poor  old  plant  proposed  low  the  electricity  extensive  demonstrate  facility,  and  The p o l l u t a n t  undertaken  also  relatively  EPA r e s t r i c t i v e An  (16  The  over  the  cost (5).  2%  is  GT120  ratio  The  built.  cycle  800°C. but  who  When  The c o m b i n e d c y c l e  increase  conditions  The  efficiency  requirements. 33%,  tube  of  AEP,  PFB p l a n t  pressure  temperature  lower  the  steam  8).  boiler.  facility.  combined c y c l e  (Figure  bed  by  existing  intercooled  plant  inlet  fluidized  operated the  largest An  the  been  data  cleanup with  on  lives. constructed  A  to  prior  to  and  solids  satisfactory  turbine  Alloys  and  blade  were  selected  component at  Malmo  and  test  Sweden.  11  This  facility  together  is  on a  small  A decision modification  of  National Two  small  including cleanup larger  short  by  12 of  gas  made  Board  (U.K.)  PFB at  in  m,  and  work  recently  2.0  components  by  bed  Board  done  tube  can  thermal  power  rating  510  MWt c a p a c i t y for power  of  the  research  at  by  It  at  is  (80  proposed  and  (NCB) at  Coal  of  by  only.  facility, hot  gas  tests.  is  A  It  is  operated  (41).  The  pressures  from  MWt) i s Tidd  neither  in  limited  Grimethorpe.  operate  and  wear  the  built the  this  (IEA)  England  m and  the  run  blade  Agency  X 2.0  its  been  durability,  turbine  of  have  with  maximum p r e s s u r e  been  Energy  but  for  its  proceed  (40).  commissioned  bar,  used  is  (CURL)  has  retention,  Coal  PFB i s  the  to  facilities  performance,-and  National  of  whether  Leatherhead,  International  turbines  1984  Laboratory  X 0.6  was  are  operation  research  experimental  the  facilities with  plant.  0.9  facility  the  to  Tidd  sulphur  Grimethorpe 6  the  equipment  funded by  be  Research  Much  the  scale.  first,  size,  test  will  Coal  The  Utilisation  6 Bar.  to  important  England.  its  used  has  s t i l l  plant. been  well These  coupled  generation.  British  Columbia Hydro  and  Power  Authority  British  Columbia Hydro  and  Power  Authority  (BCH)  has  been  12  considering deposits  a  in  central  they  have  been  steam  tube  cycle  Recently, the  speed  PFB  British  gathering similar  because of  facility  of  Hat  (13).  experimental  to. t h a t  of  burn  Columbia  reduced  development  to  the  proposed  demand Hat  for  Creek  Creek  coal  Working  data  for  for  the  power, PFB  from with  an  their CURL,  intercooled  Tidd BCH h a s  project.  plant. reduced  13  2.2  Review  Of  Several performance made  by  have  PFB  cycle  however,  conditions,  performances Company, reports tube  Ltd  Table It  analysis  in  uses  the  analyses are  supporting to  one  compare  different  operating  performances,  and  often  coals.  have  dealt  main  PFB  performance of  these  difficult  with  their  of  the  cycles.  Gilbert/Commonwealth  the  tube of  that  the  in spite  (6)  the  comparative  Brown, have  air  results  of  variation  the  variation  between  a i r heater  a l t h o u g h the  large  conditions  the  the  cycle,  operating  be  two  summary  appears  because  may  is  modelling  both  heater  and  Boveri  &  released  and  others are  steam included  1.  steam  occurs  each  of  interest  It  unidentified  and  comparing A  an  Most  d i f f e r e n t component  the  (1)  cycles  have  publications  of  completed,  cycles.  which  because  Analyses  been  combined  assumes  recent  And  arrangement.  d i f f e r e n t or Two  the  analyses  organisations  results  in  Models  of  particular  burns  Published  that  appear  t o be  steam  differences  tube  in  actual  between  fact  the  cycle  the  is less  difference  studies. cycle  identical. results.  cycle  efficient  A  is  This  than  unclear variation  arrangements There  is also  major  factor  arrangement  and  and some here,  operating  conditions. Several remain  aspects  uncertain.  of The  efficiencies  are  assumptions  undefined.  difference  PFB air  inconsistently  i n performance  Even  combined heater  cycle and  reported, in  between  the the  system  steam with  tube  effects  comparative  two  performance  cycles  cycle  of  design  studies,  varies  the  greatly.  1 4  It  is  also  in  efficiency  variety due  of  to  over  steam  which  The  tube  compare  the  cycle  pressurized  study  In  particular,  heater  arrangements  is Of  objective  performance  The  air  assumptions  And Scope  primary  the  cycle  has  conventional pulverized coal  arrangement  Objectives  cycle  whether  differing  unclear 2.3  unclear  the  this  bed  on a r e a s  four  A  analysed,  conditions,  but it  is  efficient.  study  two m a j o r  fluidized  concentrates  most  facilities.  been  operating  advantage  Study  of  of  and  have  an  is  to  estimate  classifications  power  left  generation  unclear  sub-objectives  of  by  were  and  combined  facilities.  previous  selected  work.  for  this  project. •  The p e r f o r m a n c e are  the  objectively and  that  steam  tube  magnitude  of  the  Both  cycles  design the  heater  also  parameter  was  compared coal  variation of  the  system  The p e r f o r m a n c e  of  the  steam  heating The  has  design  recuperation,  not  been  concepts  combinations  of  determination  of  the  these their  tube  the  consistent.  efficiency The  of  effect  examined,  and  cycles  studied  work h a v e  or  with  regenerative  components value  not  but  a of  defining  performance.  systematically in past  indicated  efficient, was  also  cycles  operating  work  plant.  is  sensitivity  intercooling,  more  to  tube  similar  difference  pulverized  steam  Previous  cycle the  and  using  constraints.  are  conventional  air  compared,  conditions  reported  •  of  compressor feed  water  the  past.  in  included with  no  various objective  optimum p l a c e m e n t .  The  15  effect  on  Several  component  determine •  efficiency  Another  the  of  Hat  coal.  combustion (2-4%), is  high  system Creek  in  at  comparing  the  performance wide  range  with  load  low  fuel  a  stages  of  low  operation  is  the  air  to  to  determine  in  ash.  and  has  of  heater  conditions.  The  the cycle  burning  in Hat less  and  of two is  for  sulphur Creek  coal  than  1%  treatment  performance  coal,  also  the  simulated  washing ash  when  high  selection  dry,  load  are  ash  performance  of of  and  is  coals  determined.  several  along  part  is  of  the  models  and  effect  determined.  modelled,  PFB s y s t e m s  of  dry,  moisture  is  were  project  cycle  Most  published  The  coal  this  combined  efficiency  modelled The  in  component  configuration.  of  relatively  sulphur.  •  optimum  performance  each  combinations  objective  Creek  of  and  on  of  Hat  drying  is  Illinois  #6.  interest  when  cycles.  The  modelled  over  a  16  III.  3.1  Modelling  DESIGN  programs  thermodynamics, no  is  in  performance work.  and  utility  facility  thermodynamic  and  exit  Figure  each  9.  The  ambient  inlet  each  of  component  simulations  theoretical  programs  follow  and  the  and  mass  PFB  power  from  gases  combustion,  the  cycle  the  an  inlet  conditions  tube  and  based  flow  at  on  experimental  the  flow  cycles.  generation are  steam)  cycle  cycle air  air  and  isentropic  steam  tube  with  combustor  of  the  and  calculate  the  entrance  an  analysis  mass  are  analysis  flow  starts of  calculated  assumed  The  air  is  pressure,  using  two  gas  compressor  efficiencies  5%  1  kg/s.  The  the loss  used  in  to  in the  compressed  compressors  shown at  from  pressure  then  are  is  known due  to  to the  series.  The  determine  the  temperature.  The  air heat  combustor pipe  the  steam  equipment.  reduce  for  the  combined  combustion  for  silencing  outlet  the  simulate  Analysis  chart  of  PFB  properties  flow  properties  MODELS  component.  Cycle  compressor  to  transfer  developed  (air,  the  A  written  analysis  fluids  Steam  heat  operation,  data  of  were  size  The c y c l e  working  SIMULATION  Strategies  Computer  Since  LOAD C Y C L E  are  inside  is  then  loss  piped from  transferred the  air  into  the  PFB c o m b u s t o r s .  the  system,  the  back  to  turbines  ducting.  the  The h e a t  hot  lost  In  gases in by  order  leaving a  the  to the  co-axial hot  gases  1  leaving  the  combustor  combustor, the  are  heat  the  set  in  The  bed  the  air  and  data  is  and  thermodynamic  temperature allowing  of  heat  turbine  with  30%  the  inlet  air  losses.  determined  coal  excess  gas  entering  the  The m a g n i t u d e  by  the  temperatures,  and  removed  air.  of  difference  both  the  in  The p r o d u c t  the  PFB  excess  by  sorbent  are  leaving  combustion  is  heat  properties  the  the  is  u p by  of  which  input.  mixed  maintaining  picked  system  exchange  bed,  excess  thus  m i n i m i s i n g the  co-axial  between  is  7  gas  fluidized composition  then  calculated.  is  in  heat  boiling  the  set  the  The  input  to  be  calculated.  water  in  the  bed  data, This  coolant  tubes. The  gases  H.P.  compressor.  set  to  make  resulting  then The the  the  use  of  L.P.  turbine  drop the  method  The  turbine  power  system  power  determined across  the  The to  the  the  used runs  the  across  to  and  H.P.  L.P.  turbine,  turbine  ambient  work  outlet  is  equal.  is  compressor,  and  outlet and  turbine  pressure  and  the  the  the  same  conditions.  generates  outlet  The  determined  Similarly,  the  the thus  efficiency.  alternator The  runs  turbine  turbine  determine  an  the  which  the  gas  pressure  is  pressure  drop  economiser.  steam  corrosion  to  the  is  economiser  temperature  drop  compressor  contribution. from  H.P.  isentropic  powers  calculation  the  enthalpy  H.P.  pressure  with  enter  tranfers  system is  in  feed  set  to  the  stack.  heat  from  water.  1 0 ° C above  the  The the  Because  of  acid the  turbine  economiser dew  point  exhaust  gases  outlet to  limit  interdependence  of  gas the the  18  power and  turbine the  and  economiser  pressure  solution  is  The  drop  reached  steam  across  only  system  performance,  after  is  the  turbine  inlet,  determined,  along  with  maximum  data and  input.  The  component First,  (160  pressure  and  turbine  steam steam  is is  conditions turbine Hg)  back  also  both  saturated  water  using  an  to  and  isentropic  The  economiser  exhaust  is  superheat,  by  pumped  then  and  to  and up  to  the  heat  of  gained  required  to  to  using  the  PFB,  the  reheated  the  6.75  heater boiler  outlet  matching  (2  cycles.  are  in The  by  the  calculated,  is  that  and  The  KPa  pressure  The w a t e r  boil  and  efficiency.  conditions  81%.  are  reheat  The  with  set  air  rise,  the  reheat  isentropic  heated lost  by  superheat  in the the  calculated.  flow  is  the  gas  system  reheat  the  steam.  from  the  was  the  (540°C)  calculated  turbine,  pump o u t l e t  heat  mass  the  tube  the  are  pressure  efficiency  with  available  L.P.  in  conditions  expanded  In  are  iteratively.  maximum t e m p e r a t u r e .  the  The  gases.  boil,  the  run  combustion  transfer  to  then  pump.  steam  efficiency.  system  temperature  temperature  conditions  steam  is  then  main  condenser)  inlet  is  condenser  the  economiser,  The  turbine  determined  liquid  feed  the  isentropic  determined  steam  outlet  correct  temperature,  economiser  superheat  the  point,  the  The and  steam  known  The  exhaust  for  the  used  are  next.  reheat,  flow,  steam  Bar).  heated then  mass  drops  H.P.  using  pressure  steam  steam  pressure the  calculated,  the  dew  iterations.  calculated  (H.P.  acid  economiser,  several  pressures  the  calculated and  from the  heat  The pumping  the  PFB  required power  heat to  losses  19  through  the  calculated loss  as  is  friction  losses  across  is  natural  analysis to  and  approximately  the  air  mass  flow  of  temperature  in to  the  are  coal  cooling  air  determined  input to  the  then  the  be  power  the  fluid  used  from  to  utility  The  power  The p r e s s u r e  drop  negligible  boiling  are  because  water.  determined,  After  the  entire  iteration.  of  flow air  for  is  is  bed  a  The mass  for  the  the  iteration in  the  through  than  the  is  air,  required  turbine air  inlet  with  however,  method  air  the  analysing  prescribed  the  in  combustion  The  cooling  10)  following  After  temperature  resulting  (Figure  the  processes,  estimated.  inlet  flows  has  coolant.  Newton-Raphson rate  system  much h i g h e r  used  by m i x i n g  and  gas  but  combustion  turbine  flow  cycle  cycle  air  The  temperature.  to  next  heater  used  and  gases.  data  converge  inlet  is  the  overcome  conditions.  drops.  drops  in  to  pumping  developed  similar  assumed  tube  1 kg/s  2 kg/s  compression  combustion  air  steam  with  were  of  A  are  Analysis  The c o m p r e s s o r cycle  is  reheater,  The c o r r e l a t i o n s  pressure  pressure  of .the  the  in  effect  recalculated  The  tube  to  section  Cycle  required  losses  operating  and  Heater  differences.  power  and  transfer.  component.  circulation  is  heat  power  converted  Air  similar  steam  data  flow  system  of  pumping  superheater, the  given  boiling  steam  steam  in a  then  the  the  the  the  are  of  amount  component  losses  of  fractions  the  estimate sized  economiser,  is  the set used  turbine  compressor  corrected.  There  are  two  other  differences  with  the  air  heater  gas  20  system.  Because  only  one  gas  also  no  The  cycle ' is  exhaust  gases,  steam turbine  heat  was  in  are  much  HRSG  a  The  loop,  and  on t h e  heat  and  temperature The  This  provide  pressure  too  to  drops.  second  very  80%,  steam  the  turbine  result  of close  the to  heat  in a  occur  steam  temperature  of  one  the steam and The  steam  drum  entering higher  the  steam  superheat HRSG  temperature. areas  and  constrained.  quality  would  boiler  pressure  quality  boiler entering the  gases,  overall  surface  also  generator  exhaust  superheat  exhaust  liquid  turbine  system.  a  The  The  the  steam  of  steam  with  exhaust  safe  with  tube  transfer is  gas  air  pressures  turbine  the  blades.  saturated the  the  the  bank.  improves  turbine  is  these  tube  only  section,  gas  pressure  of  most  is  recovery  limiting  acceptable  the  cycle,  pressures.  the  to  of  from  steam  tube  the  efficiency  at  the  heat in  There  in  steam  There  heating  pressure  p r o b l e m may a l s o  temperature be  set  the  The b o i l e r  damaging  therefore  may  set  pressures, low,  of  boiler  is  is  water  used  operating  in  superheater  and  and  the  used. Neither  the  tube  PFB's.  than  available  effectiveness  high  a  cycle  temperatures  and  (HRSG)  from  steam  intercooling,  performance.  HRSG c o m e s  the  lower  performance  turbine.  in  preboiler  depends the  the  done  temperatures  boiling  cycle  the  are  considered.  generator  for  reheat,  contains  the  for  turbines  different  no  and  and  two gas  steam  whereas  consideration  exchange  quite  the  heating  and  affect  recovery  A l l of  no  heat  however,  heat  system.  is  compressor  co-axial  differences  heater  there  of  become  gases  is  88%.  pressure. the  At  boiling heating  A The  zone that  21  of  the  point.  HRSG If  becomes  large.  of  the  small,  an  HRSG 3.2  was  to  temperature  the  also  pinch  the  pinch  point  requirements  become  heating  to  80%,  differential  the  boiler  the  feed  the  in  order  water This  gap  conditions  section  throughout  pressure.  increases  operating  boiling  water  limited  lower  thus  the  at  area  feed  reduce  the  section  lowers  in  to  the  p r o v i d e d the  the  pinch optimum  Sub-models  Thermodynamic P r o p e r t y  pressure,  density. exit heat  of  of  each  program  independent  properties  interest  enthalpy, are  in  the  cycle  in  entropy,  determined  which  this  are  and  uses  study  this  study  specific  heat  at  the  entrance  are  used  primarily  in  terms  enthalpy  or  calculations  temperature  The  air  and  and p r e s s u r e  properties. properties  formulated  The steam  properties.  for  independent  component  properties.  independent developed  properties  of  calculations.  the  independent existing  temperature,  These  balance  All  as  Calculations  thermodynamic p r o p e r t i e s  include  such  of  to  The r e s u l t i n g  The  and  transfer  used  D e v e l o p m e n t Of T h e  and  heat  temperature  and  called  differential  therefore  method  is  performance.  3.2.1  in  is  adequate  effectiveness  point.  the  This  The e f f e c t i v e n e s s  The  boiling  11).  temperature  HRSG  maintain HRSG.  the  too  too  (Figure  In  may n o t  entropy  be  may  gas  and  many  given.  based  density  For  on  an the  formulations  were  temperature  and  two  as  situations  known, be  and  are  of  one  another these  are  the  of  the  property situations  22  a  s e t of i t e r a t i n g  thermodynamic  routines  fluid  was  created.  properties  The  i s performed  calculation i n the  of  subroutine  library. Some s t e a m vapor,  and  conditions the  thus  calculated  in  each  in  with  different  i n the routine  fluids  International 1968.  The  function are  Appendix  of temperature  and  calculations developed  using  Calculations  i n t h e gas  being  routine  previously  The c o m p o s i t i o n i s  i s  used,  maintaining  The g a s c o m p o s i t i o n i s  the computer  gases  routines  are  f o rthe  properties.  o f Steam  property  calculations for  steam  represents  contained  The  derivatives thermodynamic in  by K e e n a n , K e y e s , H i l l ,  an  based  accepted  o f Steam  the Helmholtz  and d e n s i t y . the  are and  f o r the Properties  appropriate were  (with  properties  calculations.  developed  equation  throughout  "MIX", w h e r e c o m b u s t i o n  Properties  Conference  or  The  composition  A lists  and t h e i r  state  calculated  energy  gas  region).  p.  liquid  i n s i t u a t i o n s where t h e  t h e SOx c o n c e n t r a t i o n s .  air.  of  and  one z o n e ,  are valid  point  a gas p r o p e r t y  thermodynamic  equation  routines  the combustion  Thermodynamic The  the  i n only  t o be u s e d  Other  on  time  modified  mixed  only  P,T,H,S,CP,  depend  equilibrium also  are valid  of the c r i t i c a l  are  determined updated  are  a r e known.  exception  routines  routines  free  energy  the Helmholtz identities.  (7) and  in as a  properties  e x i s t i n g computer  & Moore  an  by t h e  (ICPS)  remaining of  on  this  free These  routine routine  23  was  used  as  computing. pressure  the  The and  entropy,  two  density,  vapor,  This  the  order  to  (8)  was  iterative  and  testing  of  steam  and  the  thermodynamic  density  calculates  be  the  enthalpy,  joule-thompson  given is  from  the  and  and  the  not  to  Cycle.  state,  valid  liquid  inside  Air  is  nitrogen  and  were  the  and  the  library  routine  and  along  with  calculates  the  and  enthalpy  when  three  routines  permit  calculation nine  ICPS  temperature  other  of  given the  properties  routines  thermodynamic  of  gases to  their  defined  the  in  (Appendix  properties  when  known.  was  however,  23.29%  Another  entropy  Properties  and  boundaries,  subroutine  addition,  The method  is  the  calculate  This  saturation  These  combustion  flows  routines  of  In  properties  programming.  of  steam  saturation  solution.  zone.  Thermodynamic  Heater  in  condition  created  parallel  exists  temperature.  saturation  Air  also  between  properties  pressure  different  find  heats,  the  included  reverse  saturation  were  steam  to  the  then  must  determine  pressure  A)  and  of  region.  relationship  the  iterates  routine  approved  an  all  specific  in which  phase In  routine  for  temperature  coefficient. or  core  of  A i r and are  allow  Gases  handled the  separately  in  the  consideration  of  two  in  the  Air  mixing,  as  the  property  calculation  case in  of  both  sets  similar. as  oxygen  dry  and  (by  mass)  an (9).  ideal  mixture  of  76.71%  The c o m b u s t i o n  gases  24  are  treated  vapor,  ideal  oxygen,  monoxide are  as  and  not  mixtures  sulphur  NOx a r e  large  calculations.  The  determined  in  nitrogen,  dioxide,  not  enough  of  and  included  to  sulphur  because  significantly  concentration  the  carbon  combustion  their  gas  Carbon  concentrations  the  each  and  water  trioxide.  affect  of  dioxide,  thermodynamic  constituent  mixture  is  calculation  rout i nes. In this very  the  range  study, close  it  to  Since  functions  of  terms  both  were  based  on  3.2.2  and  has  significant the  the  the  pure  temperatures the  and  (Cp)  S,  B).  and  the  Coal  In  A Fluidized  of  coal  typically  800  to  between  PCB a n d  900°C  pulverized  coal  boiler.  at  compared Also,  molal are  due  mixture  ideal  gas,  are is  the  solely  given  in  properties  properties.  Four  calculated  using  Bed  Pulverized There  place  an  was  properties.  studied.  differences takes  a  as  gas  The m i x t u r e  p)  as  extensively  known  ideal  Entropy  partial Cp,  in  of  in  factor  formulations  pressure.  component (H,  use  treated  (Appendix  encountered  compressibility  the  is  heat  temperature  combustion  that  mixture  properties  Of  and  permits  temperature  combustion  been  This  specific  Combustion  The  found  temperature  thermodynamic pressure  was  and  of  pressures  unity.  calculations. enthalpy  of  Coal  are  Boiler  however,  PFB c o m b u s t i o n . lower  ("PCB") several First,  a  much  to  approximately  1650°C  to  thorough  mixing,  bed  temperature, for  a  PFB  25  combustion  is  temperatures boiler.  almost  rise  This  This  particle, and  gas  it  flue bed  rapidly  as  particle  affects  to  pass  the  gas  through  the  emissions.  diameter  longer  PCB h o w e v e r ,  the gases  NOx  compared  in a  a  is  75  much  ^m f o r  the  combustion  the combustion  larger  a  conventional  time  boundary  in  for  layer  each  thickness  composition.  is  the c o a l  formed  gases  (10)  however,  combustion from  results  In  increased  600 urn a s  and  Thirdly, as  in  t h e mean  typically  systems.  and f a l l  results  Secondly, PFB,  isothermal.  as  it  passes  at  of  efficiency,  transferred  to  Finally, coal,  there  with  sorbent.  along  significantly The  in  usually  found  in a the  with  heat feed  the  moving  contained  standard  upwards.  different  by b u b b l e s  results  To  in  is  the  the  drained  maintain in  the  fluidized  remain  The hot ash  loss.  with  a  high  solids  is  water.  in a  in fluidized  bubbles  In a  zone  combustion of  reactions  the coal must  bound  for  sulphur  therefore  differ  PCB m e t h o d s .  several  dense  remains  sorbent  calculations  particles  through  and  PFB c o m b u s t i o n from  characterized  heat  combustion  the b o i l e r .  reaction  gases  operate  ash  the  (50-80%)  the a d d i t i o n a l  coal  combustion  the ash  through  the  the b o i l e r  is  PCB l e a v e s  the bed temperature.  the PFB, r e s u l t i n g  thermal  in a  a n d much o f  the bulk zone  ash  zones in a  of  coal of  coal  PFB a r e  Although a modes,  particles.  by t h e  fluidized  the  particle  This free  The m i x i n g  efficiency  of  flow bed  bubbling  combustion.  relatively  combustion  supported  regime regime air  effect  between  of can is is  rising of 99  the and  26  99.9%, gas  and  flows  beds  in  a  greater  (11,12).  the  for of  a  preset  air  of  thermodynamic heat  subtracting  S02  and  heat  of  air,  fresh  sorbent.  temperature outlet  to the  solid the  made  the  solids  efflux  the  library  coal  the  required The  amount  Ca/S  using  ratio.  the  preset  factor.  using  the  The  criterion  set  up  water,  analyses  dioxide. but the  are  The is  not  raw  coal,  combustion  available  for  transfer  cooler  calculated  in  is  content  in  this  to by  between  temperature.  spent  the  taking  the The  bed  cooler  study.  Products  molecules sulphur,  small  which and  contain  may  be  thermodynamically The  carbon  carbon,  nitrogen.  concentrations  chlorine  programming.  by  the  and  ash,  calculated and  200°C  complex  is  ash,  outlet  to  tubes  gases,  heat  cooler  was  oxygen,  in  cooling  The heat  of  included  the  contained  is  agent,  determined  combustion  Coal  carbon  by  retention  are  in  system.  sulphur  Reactants  some  the  determined  fluidized  of  calculated  Combustion  in  mass  to  the  out  are  Coal  corrosive not  in  temperature  included and  in  and  hydrogen,  added  is  S03  energy  water  difference  is  the  equivalent  of  carried  routine,  than  equilibrium.  the  the  to are  and  released  the  feed  99.5%.  set  products  from  steam  was  required  sorbent and  efficiency  ratio  efficiency  concentrations  The  fuel  coefficient  combustion  this  combustion  combustion  of  In  carbonate  main  transfer  calculations  "BED".  calcium  The  The  programming  Combustion subroutine  heat  of  Also  chlorine  important  as  a  significant  and  is  dioxide  can  be  27  divided  up between  oxygen  separate  constituent  clays  metallic  and  contained  in  in  of  a  range  correction, (Appendix  enthalpy  could  choice  of  fuel  As R e c e i v e d ,  moisture U.S.  removed;  coal,  is  of  Creek  Hat  was  of  found by  pure  need a  for  number the  was  a of  heat  determined with  a  silicon  4%  dioxide  and  When products,  of  B.C.  burned,  coal  necessary  was  the was  used  reacts  to  to  forms  of  determine  eliminated  from  which  are  thermodynamically  A  of  standard  each  for  coal  was  main  analyses  at  large  variety  of  SOx.  products which  otherwise  developed 10  dissociation  concentrations  some  It  was  formed  formed  in  significant  were  in  small then  calculation.  was  fuel  with  and  which  not  the  Washed,  simulated  a  NOx  and  of  were  the  form  quantities  of  coal  Ash F r e e .  for  The p r o d u c t s  concentrations  Creek  Hat  performance  concentrations.  program  the  also  significant  the  to  Hydro.  including different  therefore  of  Dry and  #6  version  suggestion  importance  Dry;  Illinois  washed  primary  no p r e p a r a t i o n ;  the  as  of  that,  with  determined,  coal  up  ash  variations  Although  effects  the  calculate  Four  purposes.  A  made  to  modelled  comparative  the  is  order  It  be  calculations.  considered:  eastern  the  eliminating  Ash  In  temperatures. ash  combustion  and  category.  oxides.  ash,  carbon,  B).  The  ash  and  and  were  to  combustion (Appendix typical  products B).  Using  PFB c o n d i t i o n s  calculated  significant  determine  (Table  constituents  the and  ash a  included free  set  2). are  equilibrium  Hat  of  Creek  component  The carbon  the  only dioxide,  28  water,  oxygen,  available  and  experimental  concentrations between  between  6 and  50  ppm  the  combustion  from  equilibrium. Part  due  to  of  more  equilibrium  and  bed  after as  result  of  Upon  form  oxygen  It  was  differed by  calculations these  two  performance,  may  than  to  zone. of  nitrogen much  where  and  is  much o f  has  flow.  reactions alter  NOx f o r the  less  the  oxygen  Accordingly, from  the  of  they  is  are the  the too  gas  bulk  carbon  will  speed  of  slow  at  composition  example,  nitrogen  even  will  impurities  not  though  form in  the  dissociate  to  the  equilibrium  lower.  although  the  the  them  is  assume  50  ppm o f  do  not  omitted  concentrations total  neglecting  were  that  significantly  concentrations  significantly  equilibrium,  they  levels  equilibrium  non-equilibrium  particle,  constituents  monoxide  significantly  the  combustion  the  oxide  higher.  to  that  from  bulk  with  nitric  differs  hotter  the  differs  combustion  be  bed  agree  concluded  particle  is  dissociation  the  therefore  the  zone  leading  and  found  from  This  be  the  leaving  concentration  caused  of  the  of  not  carbon  departure  particular,  temperature  coal.  the  zone  effect  leaving  a  for  ppm a n d is  do  indicates  fluidized  layer  this  NOx w i l l  Many  a  dioxide  In  Another  the  It  place.  in  calculation.  reaction.  (11,13).  boundary  carbon  monoxide  220  in  results  which  and  reason  takes  These  data  90  process  the  the  combustion and  nitrogen.  0.12%  error  250  otherwise the  in  (Appendix  CO, and  from  of  CO a n d  heat  release  C).  ppm o f  NO  These  NO.  Since  the  cycle  affect  calculations.  S02  and  29  S0  3  were  the  i n c l u d e d because  acid  dew  combustion Ash,  CaSOq,  3  Sulphur SOx  point.  products  CaC0 ,  emission  damage  important  cause  development  and  important gases. dew  PFB  on  sulphur  from  it  is  study  known has  2  effect  on  significant  ,  0 ,  S0 ,  S0 ,  predict  the  2  2  3  stack  the  gas  causing  Also,  SOx  trioxide and  are  gas  including  systems, SOx  has  is  been  undertaken considered  to  the  done  reduced  in  study  only  to PFB  cycle  because  concentrations acid  dew p o i n t  temperature  were  to  acid  would  start  corrosion.  be  tolerated,  the  minimum  the  work,  the  sulphuric  may  S i n c e SOx i s t h e most  that  been  to  of  performance.  determine  the  much  emissions  they  made  a plant.  generation  because  on w h i c h  combustion  2  normally  of  condensation  based.  are  power  system  surface,  criterion  2  rain,  this  sulphur  point,  stack  and  Coal.  calculation  If  H 0, N  C0 ,  acid  Since  since  effect The  generation  thermodynamically  Unburned  expected of  of  performance, their  heat  therefore:  estimates  emissions.  systems,  The  are  and  their  Emissions  pollution  reduce  of  reactions  and  calcium  their  effect  the stack  of  drop to  are of  dew  onto  some  is  an  to  sulphur  sulphate  add  to  should  be  considered  is  converted  acid the acid  important  temperature  sulphur  stack  the  condense  point  gas  the  below  Although  also  the  may  dioxide, heat  in  be  the  of heat  calculations. When  coal  is  burned,  the  sulphur  to  either  30  sulphur  dioxide  equilibrium  total  the  and  SOx a t  After  high  particles  retention  of  bed  (Table ratio  3). of  (Ca/S)  t h e number in  compared  the to  retention best  of  of  bed.  sorbent  2:1 near  50% t o  coal  of  The  in the c y c l e  which  low 5% o f  into  contact  with  is  absorbed.  The  added  at  is  Creek  and i t  be u s e d .  resulting  is  limestone  i n terms to coal a  low  reaches  Anderson  facilities  Creek  given  calcium  typically  C) w o u l d  coal, Sorbent  t h e CURL  indicate  site,  on t h e  and q u a n t i t y .  Anderson  sorbent  (14).  analyses,  both about  sulphur  type  results  the proposed  (Appendix  for  95% d e p e n d i n g  and  sorbent  Ca/S  come  experimentally  moles  dolomite  at  limestone used  The mass  of  and sorbent  Hat Creek  by  The  conditions.  from  was d e t e r m i n e d using  and accounts  the  performance  (S03).  enhanced  a n d some  varies  trioxide  is  gases  conditions,  England  S03  the sulphur  fluidizing  in  sulphur  pressures,  typical  combustion,  sorbent  sulphur  or  concentration  temperatures the  (S02)  of  sulphur reactivity  95%  sulphur  limestone likely  A Ca/S ratio  the  is  that of  the this  4:1  was of  in a  sulphur  retention  by t h e  sorbent  leave  81.5%. The and At the  cool  sulphur  gases  as  pass  they  the lower  was  i n the  found  the  concentration  the  available  content  through  temperatures,  equilibrium It  not absorbed  of  data,  and a c i d  SOx e q u i l i b r i u m  stack  that S03  the t u r b i n e s  results  the a c i d  resulting  dew p o i n t  in  shifts  exchangers.  toward  in approximately  dew p o i n t  i n the gas  and heat  (15). a  correlation  (Appendix C ) .  was  S03  and  95% S 0 3 .  was d e p e n d e n t A curve  the bed  o n l y on  fitted  between  to S03  31  There  are  S02  to  S03,  the  ash  (16).  cannot  be  catalysts  several some  reliably the  non-equilibrium equilibrium  method  results  The maximum the  processes  given  heat  differential  between  longer  tube  cost  electricity  the  heat  friction. around In assumed as  the  were  effectiveness is  The optimum  is  actually  of  these  used  The  points. in  The  this  study,  dew p o i n t .  minimum  This  stack  hot  and  cold heat  because  and heat  the  of  the  by  gas  transfer the  exchanger  the  the  Usually,  area.  drop  the  temperature  drops,  increased  pressure  of  increasing  however, fluids  large  fraction  transferred.  enhanced  a n d more  exchanger,  gases  CURL.  effectivenesses  rises  in  histories.  dew  acid  the  sulpur  of  Effectiveness  is  the  lengths  by  the  present  action  acid  therefore  with  conversion  the  the  lower  agreement  which  At h i g h  in  of  temperature  of  efficiency  effectiveness.  of  And  heat  and  the  by c a t a l y s t s  to  estimates  exchanger  possible  cycle  of  time  BC H y d r o  Exchangers  due  result  close  to  control  assisted  estimated  imprecise  in a  which  concentrations  in conservative  Heat  are  concentrations  temperature  3.2.3  which  The a c t u a l  and  resulting  of  reactions  requiring The o v e r a l l  capital due  effectiveness  to is  cost fluid often  80%. this to  be  heat  study,  the  linearly transfer  pressure  related  to  drop the  increases,  across heat  the  heat  transfer allowed  exchangers  is  load.  Thus  pressure  drop  32  increases. cycle  This  method w i l l  performance  cycles.  The  transfer  are  valid  high  at  Steam  using  included (greater  Tube C y c l e  compressor,  high  increase  the  resulting may  in lead  first  exhaust used  in  to  can  the  to  Heat  the  the  fuel  decrease be  the  done  air  correlations  the  air  work  and  A  in  cycle  or  heat are  not  the  low  two  In  the  In  tends  the  the  temperature, Brayton  cycle, cycles,  (Figures L.P.  Cooling  further  to  of  combined  stages  from  to  decreases  effect  exhaust  feedwater.  stage  This  negative  heat  leaves  therefore  efficiency. one  it  density.  consumption.  in  second  after  compressor  transfers  steam  optional  and  Exchangers  efficiency.  intercooler air  cools  reduce  a  drop  similar  Recuperators  higher to  These  in  of  effectivenesses.  compressor  cycle  is  intercooling The  Optional  comparison  exchangers  pressure  C.  85%)  increasing  pressure  intercooler  this  and  Appendix  reasonable heat  between  than  intercooler  pressure the  in  a  different  correlations  Intercoolers The  provide  8,12).  compressor  water  lower  may  the  be air  temperature. Recuperators to  the  air  entering  particularly otherwise  useful  wasted  consumption. is  less  used  to  transfer  In  certain generate  the in  heat  combustor  Brayton cycles  turbine  exhaust  combined c y c l e  because steam.  from  the  the  turbine  (Figure  13).  because heat  heat  they  to  applications,  recuperator  exhaust  can  They utilise  reduce their be  gases are the fuel  usefulness alternately  33  The  effects  recuperation components of  of  were  single  determined  i n t h e steam  cycle.  a l l r e c u p e r a t o r s and  was  and  double  intercooling  by  modelling  The  heat exchanger  intercoolers  the  included  and  individual effectiveness  i n t h e programming  80%.  R e g e n e r a t i v e F e e d Water H e a t e r s Regenerative used  to raise  the  entering  the  for  cycle  the  is  The  14).  instead means output.  thus  Since  a  larger  series.  bleed  pressures are set  The often  location  less  economiser.  of  plants, provide to  in  higher  is  feed  turbines  to heat  water  lowered.  This  f o r t h e same power  heaters  are  maximum e f f i c i e n c y ,  the b o i l e r  addition  a  the  i s used  required  equally  to  of h e a t  from  work  several  prior  by m i x i n g t h e  bled  t h e steam  is  of f e e d water optimum.  place This  across  temperature, a  steam  are  space  the  saturation  commonly  the  turbine  heater  outlet  t e m p e r a t u r e and  the  (17).  than  p u b l i s h e d which  differential  To  between  outlet  of  plants  water  resulting  i s ' accomplished  boiler  in  feed  temperature  power, t h e s p e c i f i c  used  economiser  the  average  some  In c o n v e n t i o n a l  temperatures  of  increased,  amount  of p r o d u c e that  The  heating  with a small  (Figure  heaters in conventional  temperature  boiler.  efficiency. water  f e e d water  h e a t e r s i n PFB  Several  the f e e d water results  in  the economiser  larger  cycle  economiser  lower  and e i t h e r pressure  designs  p r o p o s a l s have  heaters a  cycle  upstream mean  of  been the  temperature  a higher stack drop,  is  or  a  gas more  34  expensive should  heat  heat  In  the  the  economiser  and  feed  few  one  For  simplicity, of  recognised  than  feed  those  water  in  comparison  3.2.4  Turbomachinery  The  turbomachines  turbines,  gas  important ratio,  determine  and  machine  and  was  used  compressor  machine that  design  pressure  the  the  inherently machine  to  other  included  will  in  estimate  It  has  ratio. improve  been  in  maximum  tube  cycles. to  turbine  the it  necessary  slightly  are  study  pumps.  are  In  inlet  is  in  a  lower  expected  to  gas  and  steam  case  it  each  conditions,  Specific  be  data  is  pressure from  the  parameters.  dependent argued  (18) will  lowering  efficiency,  decrease  A  the  study.  efficiency  the  by  losses.  this  Although  cycles  done  Due  w o u l d be  drops  design is  steam  steam  this  efficiency.  is  used.  the  boiler  design  compressor  also  by  and  the  the  are  pressure  efficiency  size.  cycles,  would  the  in  result  predicted  PFB  required.  heaters  would  compressors,  to  literature The  to  heating  are  into  in  economiser.  heaters  heater  heaters  water  modelled  feedwater  This  small  the  surging  closed  the  heaters  feedwater  plant.  efficiencies  of  is  water  from  water  heater  open  that  most  feed  water  Feed  exiting  feedwater  commercial  The  water  PFB s y s t e m s  of  danger  exchanger.  resulting  the in  on  pressure  for not the power  the  ratio  steam  tube  change  with  pressure  ratio  and  offsetting  size  of  losses.  35  A typical  efficiency  cycles.  Estimates  efficiency  were  equation  was the  decrease  with  system.  Since  best  air  the  maximized.  uncertainty efficiency The  89.5%  in was  at  heater  different  set  at  88%  for  used  same  provided  temperature  as  in  does  not  steam factor  tube in  the  was  based  the  given  The  of  air  ratios.  there  heater  is  some  gas  turbine  tube  cycles  ratios.  the  steam  The e f f i c i e n c y turbine various  (21)  on  pressure and  operating  was  the  limiting  pressure  G.E.  power  formulation  under  by  an  are  steam  The  and  compressor  conditions.  operate  (18,20),  and  in a l l  recovery  turbine  D).  available,  all  gas  tube  turbines  at  was  efficiencies.  superheat  gas  resulting  data  turbine  can  were  the  a  steam  cycle  compressor  is  formulation.  The h e a t  cycle  turbines  the  the  (13).  of  power  efficiency  little  steam  operated  size  the  the  data  same m a n n e r  turbine  The  compressor  the  in  tube  (Appendix  cycle,  in  gas  used  steam  data  heater  the  was  from p u b l i s h e d  the  pressure  Unfortunately,  with  to  (19) the  compiled  capacity,  usually  86%  for  fitted  For  cycle  of  used  was  in  pressure  a  linear  developed.  The  at  the  air  ratios  with  efficiencies  and  set  of  two  correlation turbomachine  t  efficiency  correlations  uncertainty, and  sensitivity  compressor The  gas  parameter,  included  studies  were  in Appendix D. completed  for  Due the  to  the  turbine  efficiencies. turbine  having  a  efficiency.  The  corrosion  erosion  and  are  inlet large  temperature impact  temperature of  turbine  is  on  an  the  limited  blades  is  at  by higher  important plant the  cycle  thermal increasing  temperatures.  36  For  the f i l t e r i n g equipment now a v a i l a b l e f o r the  it  i s estimated that the maximum t u r b i n e  871°C f o r the a i r tube c y c l e s cycles of  equipment, the u l t i m a t e  where the bed p a r t i c l e s fuse The  turbine  inlet  approach 900°C. turbine  inlet  between  cycles,  systems,  temperatures are  (22), and 800°C f o r the steam tube  (13). These temperatures w i l l  improved  inlet  PFB  together  r i s e with the  development  l i m i t a t i o n being the point (the s i n t e r i n g  temperatures of future  systems w i l l  point). therefore  The c y c l e e f f i c i e n c i e s are presented at s e v e r a l temperatures, the  steam  but tube  when  comparisons  are  and a i r heater t u r b i n e  made inlet  temperatures are 800 and 871°C, r e s p e c t i v e l y .  3.2.5 Net E f f i c i e n c y And A u x i l i a r y Power Losses In  the  efficiency  cycle  (based  analysis  Coal  plant and  grinding,  solids  gross  to the f u n c t i o n  are  included  transport  power,  net e f f i c i e n c y c a l c u l a t i o n s are performed  manually,  and  (Appendix  when the "Net" e f f i c i e n c y i s c a l c u l a t e d .  computer a n a l y s i s r e s u l t s .  of  i n the gross e f f i c i e n c y .  a l t e r n a t o r and turbomachine a u x i l i a r y equipment l o s s e s D)  thermal  value) i s c a l c u l a t e d .  which are basic  and which are not included sorbent  the  on the higher heating  There are s e v e r a l operations the  programs,  using  The the  37  IV.  4.1  Steam  Tube  The various  gross  in  pressure,  pressures  and  reaching  a  maximum  heat  behaviour the  At  higher  addition turbine  decline  turbine  The  rises  is  following Appendix  heat  the points  also  first  1.5 of  the but  low,  resulting  performance.  The  because  MPa,  and  gas in  is  combustor and  then  cycles.  At  therefore  the low  temperature  of  in  compressor  greater  the  at  a  efficiency of  cycle  resulting  average the  with  Brayton  temperature is  tube  temperatures  rises  1 and  addition  increased,  steam  inlet  typical  pressures,  and  losses  and  increases  with  higher  average  addition.  turbine per  analyses. E.  heat  around  Washed Hat  between  inlet  efficiency  maximized  percentage  is  temperature  gross  with  900°C.  of  is  RESULTS  basic  turbine  increased,  cycle  inlet  temperature  800°C  is  work in  of  the  efficiency  combustor  temperature  efficiency.  a  of  The  pressures,  H.P.  efficiency  15.  This  ANALYSIS  Results  Figure  declines.  average  LOAD C Y C L E  PFB C y c l e  combustor  shown  low  DESIGN  with 1.2  inlet  degree  Creek  MPa  a  turbine at  A complete  38.9%.  temperature  Celcius  coal  inlet  was  the  cycle  The at  a  and  would  fuel  used  analysis  temperature  efficiency  rate be  in is  of  of 39.9%  this  0.010 at  and  the  included  in  38  4.1.1  Steam  The  Tube C y c l e  steam  includes  tube  the  safe  steam  exception turbine  efficiency  power  turbine  recuperator,  determine The  two  intercooler, increases of  1.6 work  turbine. efficiency  because  the  Compressor performance feed  gas  a  that  on  MPa. is  heat  0.25  if  the  the  for  with  in  is  heat  not  the  system points  gases  contained  modern gas  added,  16.  to  more  is  the  single  feed at  a  water,  combustor that  generation  water  were  A  is  from  air  the  to  is  the  reduces  The e f f i c i e n c y lost  the  from  however,  beneficial in  with  a  the  double)  increase  points.  therefore  and  steam  in  have  were  Figure  the  provide  intercooler,  in  cooling  percentage  contained  intercooling  (single  resulting  Intercooling  to  performance.  percentage  reason  reduced  by  to  1.4  does  heater  cycle  presented  heat  The  cycle  7)  economiser.  required  feedwater  steam  are  an  A compressor  systems  results  and  (Figure  normally associated  steam the  form,  drops system.  the  cycle  transferred  to  water.  combustor  turbine  outlet,  a  efficiency  Recuperation above  and  basic  is  this  systems.  transferring  the  compressor  the  the  which  equipment  effect  most beds,  quality,  intercooling  and  its  reheat,  generation  their  examined,  the  of  enhancing  in  fluidized  outlet  utility  power  cycle,  turbomachinery,  With  pressure  Variations  of  steam  of  steam 1.3  temperature  preventing  intercooled  basic  pressure  outlet  recuperation  the  cycles  the  MPa.  becomes  recuperating  decreases  tube  heat  cycle  At h i g h e r lower  17).  than  not  of The  possible  pressures, the  transfer.  efficiency  (Figure  is  both main  the  compressor  It the  was  found  basic  and  effects  of  39  recuperation  are  the  recuperator.  This  lowered  decreased  the  recuperation and  gas  the  tube  are  significantly  The  effect  efficiency  and  the  of  the  effect  is  seen  A  in  temperature  of  gas  in  the  economiser,  economiser  feed  temperature,  the  feed  water  heater  gains  at  is  add  to  at feed as  the  higher heat  much  heater. as  the  percentage  0.7  feed  points.  rise  the  has  thus  no  and  simple  cycle  is  to The  raising  points  is  heat  percentage  a by  with  the  effect the  the  at  the water  addition  of  a  efficiency  of  intercooling  water  temperature  efficiency with  in  feed  greater  the  rising  available  lower the  gain  because  temperature  decreasing  efficiency  pressure  0.7  reduced  lower  18),  efficiency  This  caused  cycle  to  the  (Figure  combustor  The  With  thus  increases  up  less  leading  water,  percentage  intercooled  a  pressures.  outlet, The  in  outlet.  increases,  the  economiser  water  whereas  to  exhaust  results  temperature  combustor  gain,  cycle.  therefore  water  In  temperatures  cycles  with  pressure.  turbine  and  cycles,  rejection  average  intercooled  simple  This  the thus  addition.  heater  significanty  combustor  pressure.  heat  recuperation  significant  the  and  Brayton  of  heat  the  water  and  with  combustor  and  feed  increases  the  of  ratio,  standard  of  through  efficiency.  a  varies  In  temperature  neither  simple  intercooling.  points,  power.  losses  pressure  temperature  on c y c l e  the  pressure  turbine  altered,  of  gas  average  combined c y c l e ,  addition  although  the  average  steam  beneficial  and  turbine  reduces  increases  air  the is  1 feed  increases  effect improved  water by  of  a by  heater,  only  0.25  40  Along are  specific  work two  with  is  work  the  Figures  flow.  and  total  one  are  cost  gas  the  power  fraction  provided  by  gas  work,  and  gas  configurations The  efficiency when  This  The  is  as  a  boiler  larger  heater.  transfer  In  surface  The  drops  is  is  this  intercooled  heating  is  most  however  whether  percentage heater heater chosen cycle.  is  large  and for  the  points)  an  size  and  The plant  several  which  specific  is is  gas power  specific  steam  cycle  work  11%  steam  tube  also  when  for  a  improved  consistent  a  conventional  an  efficient modest  caused  enough  to  system  feed  with  in  by with  increases  Rankine  increase  by  analysis  11% was  cycle  cycle.  increase  offset  additional  further  for  steam  water cycle. a  boiler  feed heat  indicated.  (single) the  the  total  system  required  case  for  are  4.  gas  a  There  efficiency,  significantly in  flow.  physical  of  of  heating,  happens  specific  turbomachinery.  Table  steam  criteria  The  one  the  portion  the  boiler  and  fraction  in  fluid  of  Summaries  water  • added,  means  water  but  unit  and  performance  fraction.  flow,  the  of  feed  gains.  air  power  work  intercooled,  heater  is  included  and  power  indicators  tubine  specific  intercooling  the  turbine.  are  important  per  boilers  turbine  the  power  for  rough  of  two  turbine  output  given,  They  therefore  efficiency,  It in  addition  the  cost  of  boiler  therefore  is  feed  the  of  water  questionable,  efficiency  the  of  with  the  the  surface. simple  feed feed The  (0.25 water water cycle  intercooled  41  4.1.2  Intercooled  The shown  performance in  basic  pressures.  cycle.  The  is  more  2  Appendix To  41.5%  be  and The  the  (75%  of  of was  the  of  inlet  temperature,  at  until  1.2  more  rapidly  cycle,  0.014  is  optimum  to  basic and  pressure.  turbine  the  rises  analysis  the work,  percentage  efficiency  A complete  the  combustor  due  inlet  points  per  higher from  is  in  higher  MPa f o r  with  as  much  compressor  high  is  inlet  pressure  off  to  cycle  turbine  combustor  reduced  cycle  tube  fall  difference  900°C.  with  the  determined  turbomachine in  the  cycle  strongest the  total had  capacity.  important Increasing  factor the  the  cycle  combustor  efficiencies smaller  with  operation  The  values  opposed  to  basic  the  consistent  parameters  had  due  steam  PFB  40.1%  included  at in  E.  sensitivity  factors  at  not  increases  the  and  rises  turbine  is  Results  three  MPa, as  pressure.  to  for  efficient  than  Celcius,  800°C,  intercooled  800°C  efficiency  operating  800°C  an  about  temperature degree  the  does  The d i f f e r e n c e  cycle  Cycle  19  but  With  therefore  Tube  The e f f i c i e n c y  cycle,  pressure  of  Figure  temperature. the  Steam  B.C.  efficiency  with  the  pressure  effect,  due  power). smaller  in  at  1.6  to  its  The  intercooling  cycle reduces  the  research,  secondary  inlet  the  design  temperature  found  20). large  gas on  CURL  at  MPa.  were  intercooler the  to  (Figure  impacts  and  turbine  efficiencies  efficiency  The  Hydro  to  The  important  steam  turbine  generation  capacity  turbine  efficiency  and  performance  compressor  because  effectiveness  the  be  of  is  another  (Figure  compressor  their  work,  21). and  42  therefore  increases  pressure  or  efficiency  shown  22  in  This  of  ambient  temperatures  power  is  and 25).  temperature  parameters decrease  steam  85%  of  strongly  and  thus  cycle are in  is  Since  was  the  efficiency condenser  the  the  that  in also  waste average  with  heat  of  steam  efficiency  is  found  the  holding  is  the  air  This  combustion  were  unchanged  related  (Figure  excess  the  temperatures  to  the  rejects condenser  temperature  rises  gas  the  heat,  efficiency  specific  in  condenser  efficiency  28).  reduced  gain  virtually  cycle  (Figure  is  steam  by  operating  the  constant  lost  ambient  the  beds The  the  increasing  to  varied,  the  overall  low  thereby  temperature  cycle  average  the  At  work.  by  is  MPa.  temperature,  remained  Because  3.5  ambient  fluidized  change  of  on  transferred  offset  pressure  effect  turbine  in  system.  reduced,  and  pressure  affects  also  held the  work  rise  maximum  significantly.  exactly  temperature.  approximately  The  cycle  of  a  boiler  temperatures  reheat  the  steam  little  steam  constant.  The  the  case  significant  the  26).  rejection  almost  steam  the  in  addition  with  The h e a t  less  results  optimum p r e s s u r e  intercooler  in  no  ratio  ambient  work.  The a m b i e n t  affected,  (Figure  the  change  the  resulting  pressure not  in  for have  compressor  turbine  through  turbine, (Figure  the  gas  however, turbine  conditions  conditions  an  of  coincides  addition  although  operating  system  heat  heat  effect  indicating  pressure  efficiency,  net  The  Increasing  also  average  23).  24,  efficiency.  temperature  higher  and  reheat  The  the  to  Figure  temperature  cycle  superheat  due  (Figures  the  of  heat  27).  when a l l  other  is  to  due  gases.  As  a the  43  excess  air  raised,  increased  reaching  excess  air.  therefore The  is  be  covered  in  4.2  A i r Heater  this  (Figure  29).  off  quickly  pressures, reducing a  lower  lower and  the  boiler  The  steam  Celcius). gas In  systems the  steam  affected  by  with  turbine  at  the  cycles,  gas  the  70% will  program.  varying  excess  heat  steam outlet  air  exchangers,  combustor tube  temperature  are  thus  as  temperature  (0.027 the by  higher  the  turbine  turbine  steam  inlet  more  of  system  At  becomes also  to  high lower,  results  rapidly points  inlet  the  1.1  MPa.  than per  in  degree  steam  and  temperatures.  performance  temperature.  HRSG  turbomachine  around  both  The  reduced  gas  is  percentage  operation  drops  efficiency. due  at  pressures  pressure  This  higher  optimum e f f i c i e n c y with  modelled  cycles.  turbine  well  was  combustor  temperature.  steam  as  cycle  and  high  pressure  because  improved  tube  and  high  cycles  are  at  economiser by  at  heater  at  inlet  performance  is  air  the  turbine  increases  This  predicted  temperatures  pressure  tube  the  100%  is  Results  the  indicated  efficiency  in  of  effectiveness  efficiency  power  steam  those  high  of  than  turbine  losses. The  The  efficiencies  steam  of  inlet  the  the  than  Analysis  performance turbine  losses  effectiveness  study.  Cycle  several  economiser  optimum e f f i c i e n c y  modelling  not  more  of  the  effectiveness  pressure  much h i g h e r  require  The  limiting  The  determination  would  in  the  however,  was  not  44  The one  specific  third  higher  of  gas  The  since  the  completely cannot  be  The the  boiler  gas  relatively  small  the  strongly same  steam  there  is  the  given  temperature  because,  and as  for  was  the  for  given  only  reduces  the  is  the  performance varying  cycle  point  2.30  MJ/kg,  at  cycle  Appendix  a  the  are  tube  strongly  F.  affect  turbine  inlet  compressor  points  to  much  generating  (Figure  efficiency  and  30).  moves  the  (870°C,  optimum  0.7  MPa)  a the  uncertainty  also  A  causes  and  the  therefore  design  in  performance  Due  and  steam  efficiencies  turbomachine  the  a  efficiency  one  the  increases cooling  air  the  do  not  for  the  also  does  turbine air the by  an  and  cycle. affect  intercooled  inlet  air  steam  31  strongly  not  flow  condenser  (Figures  intercooled  case  total  and  efficiency  pressure  air  air  cycle  was  in  conditions  included  in  cycle  excess  excess  flow  operating  ±2 percentage  Wright  turbine  affect  efficiency,  and  simulated,  in  steam  unit  roughly  of design  was  used  analysis.  reasons  The  was  per  analysis  pressure.  Curtiss  on  MJ/kg,  results  to  The  efficiency,  in-depth  based  0.31  This  costs  compressor  change  operating  The  and  change  turbomachine  for  cycle  870°C  work.  is  comparison  efficiencies  significant  point,  The  flow  capital  a  performance.  turbine  air  construction  turbine  of  on  cycle  work  different,  temperature  optimum  tube  specific  made.  cycle  gas  steam  based  turbomachine  capacity. but  the  work  affect  steam the  temperature possible.  flow  into  identical  and  temperature 32)  for  The  ambient  the  efficiency, fuel  combustor,  amount.  cycle  cycle.  Increasing the  the  The  flow, the and cycle  45  performance  is  temperature  and  turbine  varying  the  bed  heat  desired  temperature,  constant.  thus  remains  4.3  Effect  Of  Five  coals  and  the  were are  presented  the  while there  are a  in  strongest  range  Figure effect  is  calculated  34).  combustion amounts place  of  if  energy or  ash  during and  35)  because  effect  is  small  much  of  turbine  no h e a t  also  be  loss  between  bed  examined.  By  operated inlet  from  at  any  temperature  the  system,  the  combustion  Of  in  the  Three  of  pressures,  and  Table  combustor the  5.  fuel  a  resulting be  made  in by  source  be  lost  This  a  water  drying from  whether  in  coals  the  results  water  because the  the  efficiency  coal  of  (Figure  prior  energy.  of  Since  heat  coal  has the  heat  product.  the  the  cycles,  the  and  vapor, loss  was  is  value,  liquid as  PFB  constituents,  heating  released  to  Similar  evaporation  took  combustion. effluxes  the  heat  however, the  in  higher  sorbent of  for  Performance  efficiency.  heat  would  (Figure  recovers  the  assuming  is  would  the  of  the  lost,  gain  before Large  on  actually  Little  keeping is  on  combustion  is  can  33.  based  vaporization  bed  presented  is  water  was  the  simulated  efficiency  the  temperature  C o m p o s i t i o n On C y c l e  were  modelled at  inlet  The d i f f e r e n c e  unaffected.  Fuel  results  affected.  transfer,  Because  efficiency  not  heat  and  due  lost to  also  decrease  with the  transfers  the  efficiency  the  solid  waste.  This  solid  waste  cooler  which  it  the  to  steam  system  46  feed  4.4  water.  Comparison  The heater  Of  performance  cycle  pulverized  were  using  a  design  typical plant  feed  Results  of  boiler the  intercooled  to  each  for  a  heaters.  power  Approximate  are  included  The  gross  net  efficiencies  PFB  cycles  With PFB  calculated  at  to  demonstrate  the  technology  cycle  available  offers  percentage  points  advantage  can  development  in  were  temperatures,  of  a  net  higher  be  increased  and  one  the  net  are  today,  of  and  the  air  conventional  Rankine  cycle  was  pressure  drops  from  (Appendix  G).  reheat,  due  to  in  high  Table  intercooled  efficiency  two gas  6.  The  turbine  the  percentage  and  calculation.  improvement  PCB  The  flue  of  conventional  capable  a  efficiency  and  range  3.2  to  presented  low  to  cycle  steam  losses  operating  than  turbines  PCB  station  preheater,  desulphurization and  The  and  conditions  utility air  steam  other  plant.  operating  i n c l u d e d an  water  the  compared  coal  simulated  PCB  Cycle  inlet  possible. steam  which  tube is  plants. points  withstanding  2  This  with  the  hotter  gas  flows. The cycle  is  with  a  only  0.4  plant.  results not 900°C  indicate  significantly turbine  percentage  inlet  points  that  the  better  efficiency  than  temperature, higher  in  net  the the  of  PCB air  the  air  heater  system.  Even  heater  efficiency  than  cycle the  is PCB  47  V.  5.1  PART  Modelling  The  are  Strategies  part  achieved  LOAD M O D E L L I N G  load  in  sized.  This  performance programs The Wright 871°C  cycle  heat  part  is  load.  These  operating  point  combustor  design  design  program  was  temperatures,  used  the  of  This  program  flow  areas  design  selects  and  heat  efficiency  a  the  transfer and  also  determined.  of  the  turbomachinery  new  subroutine  calculation coefficients load  The prior  was  also  of  heat  calculation of  the  data,  heat  tube  each  the  and  transfer  diameter  was  the  Curtiss set  air  mass load  to  heater  flows  The were  operation.  and  calculates  the  heat  exchanger.  The  turbomachine  part  load  performance  can  and  be  simulated. includes heat  simulate  A the  transfer the  part  turbomachines.  coefficients  and  the  new  each  to  gas  two  chapters.  and  which  programs  system  of  exchanger  created,  exchangers  in  design  properties  includes  of  for  for  to  are  Bar.  previous  conditions  heat  transport  and  knowledge  this  and  library  of  operation  With  7  the  match  first  velocities  areas  predict  to  pressures,  operating  was  in  new p r o g r a m fluid  to  to  is  turbomachines  temperature  set  cycle  characteristics  correspond  inlet  discussed  load  chosen  was  heater  and  analysed  operating basis  air  used  was  pressure  resulting for  design  turbine  operation  load  the  steps  design  The  the  then  below.  point.  of  exchangers  described  the  The  the  are  design and  and  First  information  at  and  steps.  CYCLE  Considerations  performance  two  deterimined,  And  OF T H E A I R H E A T E R  fluid  requires  velocity.  the The  48  velocities given (U)  used  in  application of  each  the  design  (10).  heat  exchanger  temperatures  of  then  determined,  allowing  The to  a  using  data  holding the  exchanger  and  contains  point  in  the  and  for  all  of  The  in gas  maps  (Figures  are  usually  derived  The  reduced  interrelated  are  Reduced Reduced  speed, defined  Mass Speed  are  form.  and as  flow  are  to  typical were  included  parameters:  put in  a  file  for  each  heat  drops.  The  file  data  with  for  each  the  design  This  upsets  heat  given  used (24)  exchangers,  in  follows.  M * = M*/T / P  o o  this  Appendix H. ratio,  study  turbines  equation  efficiency.  curves  machine,  for  into  pressure  isentropic  N* = N//T  be  transferred  on c h a r a c t e r i s t i c  The c u r v e s as  to  This  rate.  and  are  system.  specific  The c u r v e s and  consumption  the  is  transport starts  and  (23).  areas  and  inlet  areas  program.  pressure  operate  presented  programs,  flow,  variables  in  load  each  exchanger  program  turbomachines  which  similar  load  program  throughout  36-39)  the  load  fuel  turbomachines  use  four  the  NTU m e t h o d  part  The  heat  for  coefficient  transfer  transfer  second  the  changes  from c u r v e s  have  the  thermodynamic  of  compressors.  in  in  full  reduces  axial  heat -  typical  transfer  each  full  heat  the  cycle.  equilibrium  resulting  use  are  calculated.  in  the  the  heat  then  fluid  in  and  the  then  is  Effectiveness  flow  also  the  each  calculated file  contains  load,  the  program  The o v e r a l l  outlet  calculated  load  form The  reduced The  or but are and for  maps mass  reduced  49  The  characteristic  independent ratio  curves  variables.  a r e b a s e d on  For  the  simple  P = 1 + a-fM*}* - b-{M*} 5  at  any  f o r m u l a t i o n can given  N*  by  and  c  is  derived,  f o r m u l a t i o n of b. c  and  over  the  flows,  the  By d e t e r m i n i n g  need f o r t h e  The  response to d i f f e r e n t  other  formulations  design  efficiency.  three c h a r a c t e r i s t i c  Turbine  - e-{M*}  formulations  Turbine  f  Mass F l o w  M* = g - e x p { h  •  ( N + )  k } (p)  Efficiency n  =  1  " (N*) " ( P ) q  k  S  and  change  ratios,  mass  1  Efficiency  n = d-M*  b,  function  also  pressure  following expressions: Compressor  a,  the  independent  p r o c e d u r e r e s u l t e d i n a smooth, c o n t i n u o u s  in  curve  Power f u n c t i o n s i n - N * were u s e d t o f i t a  s h a f t s p e e d s , and  The  arid c.  performance  a r e l a t i o n s h i p between  eliminating  the e n t i r e o p e r a t i n g range.  linearly  the  curves,  pressure  expression:  be made t o f i t t h e  N*  two  C  v a r y i n g a, b,  maxima of t h e c o n s t a n t  with  example, [ the compressor  f o r m u l a t i o n i s b a s e d on  This  expressions  " Ml-exp(k(p)/2}  are  based  on  50  Part A  Load  flow  Figure  40.  chart  to  pressure  function assumed  to  mass  be  performance  air  Using coolant  actual  the  heat  allowing bed bed  and  heat  air  is  the  heat  cooling  transfer  air  is  usually  determined  first.  compressor  are  are  using  the  a  initially  compressor  some to  split  air the at  between  outlet  turbomachine  ratio  past  the  PFB  combustor.  The  all  the  of  for  the  times.  The  combustor  coolant  air,  air  to  of  the  temperatures  temperatures, PFB h e a t  the  is  in  then  the  temperature  balanced  the  exchanger  coolant  generated  outlet  then  in  constant.  the  data  are  they  The  constant  The  bed  to  and  flows  estimates  for  the  presented  obtained.  kept  thus  are  speed,  fuel is  kept  tranfer  of  bypassing  air.  fluidized  exchanger  by  and PFB  also  and  values.  previously  is  properties  calculated  the  coefficient  The  be  bypass  is  air  shaft  Cycle  simulation  values,  design  preliminary  air  transfer  in  and  air  load  air  outlet  air,  inlet  controlled  level  combustion  overall is  to  determined.  determined  design  heat  load  using  program,  determined.  iteiratively  by m o d i f y i n g  The the  temperature. The  mixed  cooling  prior  exhaust load  then  the  load  and  equations  compressor coolant  part  flow  can  is  A i r Heater  efficiency  their  load  the  and  at  reducing  excess  the  design  ratio  properties  and  the  of  The  of  of  The c o m p r e s s o r  identical The  Simulation  to  pressure  program.  air,  bypass  entering are The  the  air,  and  H.P.  turbine.  determined turbine  in  combustion  the  pressure  same  ratio  gases  The  turbine  way  as  and  in  reduced  are work the speed  then and full are  51  then  calculated  determined resulting  and  from  that  ratio.  In  order  turbine,  compressor using  the  new  The the  and  the  are  turbine.  is  flow  is  then  match  the  actual  between  balance  the of  transfer two  operating  and  HRSG  to  calculated remaining  be  first,  is  the  for  and  the  three in  and  modelled.  are  design  temperature  are  the  The  flow  and  to  is  rate  pressure  that  allowed  modified.  then  HRSG  The  recalculated  inlet  machine,  H.P.  the  next  of  the  bed  the  gas  system  of  the  heat  determined  in  for  assumed.  the  an the The  balance the  which  must  the  mass  temperature, speed,  is  the  determined.  recovery  the  condenser from  must  flow,  and  shaft  permitting  mass  iteration.  bed  compressor  unchanged  mass  in  shaft  this a  iterations  fluidized  The  the  and  To a c h i e v e  characteristic  of  and  turbine  flow.  in  pressure  characteristic  By v a r y i n g  values  only  speed  are  levels  the  the  flow  are  curves.  flow  The  the  mass  condition  are  mass  to  now d e t e r m i n e d ,  and  mass  synchronous  as  efficiency  flow.  temperature  conditions  First, superheat  flow,  inlet  (HRSG)  a  turbines.  equilibrium  gas  mass  modified  heat  mass  generator  is  therefore  compressor  The  flow  are  the  actual  conditions  turbine  speed  shaft  constant.  determined  shaft  There  flows  always  power  given  expanded is  and  represents  inlet  the  then  i n c o m i n g mass  compressor  the  bed  to  This  therefore  the  flow  characteristic  flow  compressor  estimate  speed  at  match  fluidized  gases  power  mass  machine to  mass  turbine  characteristic for  the  reduced  the  possible  by  the  steam  steam  turbine  conditions design  iterative steam steam  are  values.  The  procedure. mass  flow  turbine  and  inlet  52  pressure  (boiler  pressure)  turbine  characteristics.  speed)  operation  following  of  i s then  In g e n e r a l  steam  determined  using  t h e steam  the  load  (constant  turbines  part  can  be  modelled  by t h e  relationship (25):  P„ « M • A o Knowing (at of  the boiler  saturation) t h e steam have  the  superheater  outlet is  thus  steam  then  pressure, the superheater  i s calculated.  and gases  HRSG  been  entering  determined.  c a n now  the superheater The a c t u a l  of the turbine  the turbine  temperature  a n d mass  section  heat  allowing  t o be c a l c u l a t e d .  using  inlet  The t e m p e r a t u r e s  be d e t e r m i n e d ,  temperature  recalculated  equilibrium  o  of  transfer  across  pressure  characteristic, i s  the  the superheater  The b o i l e r  and superheater  flows  thus  and the  determined  iteratively. The  feed  saturated  liquid  temperatures  water  pump  i n the boiler  from  the actual  The  mass  flow  gases  and gained  which  liquid  shift  Because  turbine When work,  then  heat  by t h e s t e a m .  the  occurs  liquid  t h e steam  characteristic  a l l of the heat and e f f i c i e n c y  transfer  mass  flow  h a s been  i s recalculated  exchangers  heat  by t h e loop at in  a  transfer  re-estimated,  the  gas  banks.  resulting  i n the next  are balanced,  are calculated.  lost  in the boiling  and b o i l e r  of  are also  t h e tube  the heat  changes,  preheater  The  i n t h e HRSG  through  The p o i n t also  and the p o i n t  determined.  i s modified to balance  saturation  between  areas.  are  conditions  at the corresponding positions  determined steam  outlet  the  iteration. cycle  heat,  53  5.1.1  Transport  The  transport  conductivity, properties  steam,  are  are  parameters  as  routines. specific  are  (26). use  correlation by  of  of  no  the  This  T  and  allows  within  transport  were  conductivity al  An  added  along  p  the  the  for easy  existing  properties, to  with the  and  is  the  the  thermal  thermodynamic  fluid  Prandtl  calculated  recommended  alternative  also  available  velocities,  and  near  the  critical  point,  point  were  required  in  from  were  Reynolds  is  was  by A l e x a n d r o y ,  this  (27). but  no  study.  This  the  use  recommended same  more  accurate in  Ivanov, equation  The  near area  for  is  the and  viscosity  and Malteev  near  by  reference.  that  used.  calculations  equation  industrial  the  required  formulation  1975  for  using  equation  formulation  calculations  in  independent  ,  developed ICPS  same  properties:  diameter,  industrial was  the  The  Steam  values,  tube  et  thermal  calculations.  of  gases.  two  alternative  point,  simpler  adopted  was  the  critical  terms  and  routines.  these  Kestin  ICPS  Although  transfer  properties  viscosity,  and  Coefficients  viscosity  calculated.  by  scientific  the  and  thermal  developed  in  and  Properties  heat  heat  transport  From  The  the  air  calculation  conductivity  Transfer  thermodynamic  computer  Transport The  the  for  of  thermodynamic  in  formulated  T  calculation  And Heat  properties,  used  with  and  numbers  Properties  and  inaccurate the  critical  54  Transport As  in  Properties  the  case  of  transport  properties  calculated  in  determined mixture  two  of the  The  and  properties.  the  The  Gases  thermodynamic  (viscosity  steps.  first  A i r and  and  pure  results  Prandtl  the  thermal  conductivity)  are  component  properties  are  are  and  formulations,  used  Reynolds  to  calculate  numbers  were  the then  calculated. The four  mixture  major  properties  constituents  small  concentration  error  is  only,  with  the  range  0 ° C to  for  thermal  points  of  to  on  ,and  the  basis  02).  Due  constituents,  the  air  of  the  to  the  resulting  mixture linear  simple  partial  methods  taking  for  molal into  of  pure  in  Appendix  a  simple  air  and  (28)  temperature formulation  polynomial  in  and  thermal  the  mixture  mixture  component.  was  The  thus  resulting  B.  thermal  composition.  kinetic  the  viscosity  The  sum w o u l d n o t  account  is  available  a  and  in  of  equation  recommended  the  as  viscosities  error  The  required.  presented  functions  B).  functions  Sutherland the  readily  same m a n n e r  are  usually  not  the  correlation  Data were  to  correlations,  minimize  (Appendix  were  the  correlations  The  N2,  remaining  fitted  conductivity  calculations  improved  C02,  viscosity  chosen  (28).  conductivity  in  were  900°C  temperature  The  the  constituent  ' temperature  treated  (H20,  calculated  negligible.  The  a  of  were  be  conductivities For accurate.  collision  this  reason  More theory  are  not a  complex provide  results. Wilke  estimation  method  for  mixture  viscosities  was  55  used  in  this  accurate  and  The  Mason  and  was  used  to  (Appendix  B).  Heat The load  is  This  Saxena  Transfer  transfer  the  to  size  were  outside  Turbulent  flow  inside  heat  The exchanger transfer  is  the  mixtures  Wassiljewa  conductivity  of  be  (28). equation  the  mixture  are  heat  required  in  the  design  exchangers,  and  in  their  performance.  the  Four  part heat  tubes tubes  outside  formulations  overall  the  to  transfer  transfer  coefficient  of  gas  shown  considered:  flow  PFB  (28)  thermal  determine  Turbulent  heat  been  pressure  coefficients  to  conditions  Boiling  low  has  Coefficients  transfer  simulation,  for  formulation  calculate  heat  formulation  recommended  calculations  load  The  study.  heat  are  included  transfer  calculated  coefficient  tubes  using  (h)  at  Appendix  coefficient  the  the  in  average  inlet  of  and  (U)  the  outlet  B. each  heat  convective  heat  for  of  each  fluid.  1/U = 2/{h 1 (i)+h 1 (o)} + 2/{h 2 (i)+h 2 (o)} h j ( i ) = Heat Transfer at hp(o) = Heat Transfer at In  some  coefficient These  cases, requires  w o u l d be  the  determination  the  determined  Coefficient of Fluid 1 the Heat Exchanger Inlet Coefficient of Fluid 2 the Heat Exchanger Outlet  calculation at  a  of of  temperature  the the  heat  film  midway  transfer  properties. between  the  56  tube  wall  calculate  temperature the  film  sophistication substituting expected  to  bulk  coefficient absolute surface  value area  the  cycle.  5.2  Part  turbine  The b u l k  of  a  90  compressor  inlet  the  module  (Figure  41).  to  a  of  the  load  was  increased expected.  The flow  air  reduced  50% to  in  not  affect  effect  heat  in the  therefore  of is  not  transfer  An e r r o r  result  to  program  properties  program.  were  stack  full of  of  acid  (Figure  possible  load  12.3  is  a  in  the  different  performance  used  gas  27%  of  throughout.  load  design steam  and  one  calculations  are  based  load  simulated  load,  down t o  the  is  were  25%  points.  The  detailed  The  determined  stack as  than  acid  dew p o i n t ,  can  therefore  part  remedy  would  load be  to  bypass  some  6  drops  indicate  at  of  by  results the  a  load  reduced  efficiency  also  on  operation  in Appendix F.  dew p o i n t  faster  full  turbine  percentage  The  the  efficiency  included  drops  on  The p a r t  the  42).  corrosion  one  cycle  At  are  based  1 kg/s.  load  loss  and  is  with  30.8%.  temperature  A  film  order  in  The  changes  would  would  heater  analysis  temperature  gas  the  analysis  F).  total  gas  stack  in  MW m o d u l e  At  points  results  the  the  properties  air  percentage 24.5%,  for  In  increase  required.  coefficient  load  (Appendix  single  significant  only  and  ^temperature.  Results  part  simulation  since  the  bulk  been  important  of  a  properties  requirement  Load  The  have  large,  are  the  properties,  would  be  and  that  gas  the the and be past  57  the  steam  generator  temperature.  A  and  thus  small  maintain  penalty  in  the  design  efficiency  stack  would  gas  also  be  incurred. There  are  several  fluidized  bed  at  bypass  can  that  air the  be  cycle and  alternatives  part'  load.  varied  air  bypass  inlet  temperature  air  is  was  flow.  not  This  affected  The  bed  height  the  did  not  significantly  but  affected  control  air,  It  bed  was  insensitive  parameters. PFB,  the  excess  independently.  efficiency  excess  The  to  to  found  because  by  variations  alter  the  i  cycle  and  however  variations  pressure  the  height,  is  the  of  the  in  the  turbine in  drop  these across  efficiency.  58  The of  objective  pressurized  systems. studied were  CONCLUSIONS  this  project  of  fluidized  Two when  VI.  cycles,  bed, the  b u r n i n g Hat  was  to  combined  steam  Creek  cycle  tube,  coal.  study  and  The  the  performance  power  generation  air  heater  following  have  been  conclusions  drawn: •  The  steam  than  the  tube  air  efficiency the  steam  heater net  heater over  tube  cycle  at  conventional cycle  net  Intercooling  is  work  significant  •  The  steam  steam  coal  was  the  steam  are  steam  tube  cycle.  should  The  cycle  air  air  is the  heater  below  the  efficiency  and  The  be  the  above  The  the  with  plant.  slightly  to  tube  of  points  cycle..  in  found  performance  35.7%,  intercooling  increases  conventional  beneficial  causes  tube  tube  drop  surface The  the  efficient  increase  included  in  is steam  cycles.  Regenerative of  •  and  Recuperation the  •  of  the  percentage  efficiency plant.  tube  2  more  system  intercooled  pulverized  conventional  specific  to  the  38%,  general  Significant  whereas  similar of  in  conventional  cycle,  is  are,  cycles.  the  efficiency  estimated  •  cycles  a  significant  loss  in  efficiency  to  cycles.  feed  water  cycles,  in  intercooled  but  specific  requirement  and  steam  heating  increases  decreases work  thus  tube  the  results higher  cycle  in  the  specific a  capital  with  efficiency  one  larger  work. boiler  costs. feed  water  59  heater The  is  the  gross  higher  than  efficiency  of  indicated  low  (37.53%)  air  heater  net in  •  The  was  found  to  control. 6.0 6.1  Areas  •  The  By  •  be  performance, part  the  with  heater tube  very  to  the  these  a  gross  of  a  50%  is  cycle.  The  turbine  to inlet  parameters  could  a  be  made,  air  heater  system.  single  part  cycle  sensitive  two  competitive  efficiency at  air  steam  module,  load  independent  combined  here.  tube  simple  of  dropped  performance the  method  with  was  of  load,  load losing  load.  Work  of  effect  points  The  performance  The  points  the  and  operation  cycle  modelled  The  cost  largely  The  could  studied.  percentage  efficient,  however,  in  simulated.  to  The  is  to  improving  more  expanded  steam  •  a  Further  cycles  as  of  efficiencies  load  study  2.2  cycles  systems.  efficiency  cycle  percentage  For  the  40.33%,  almost  increase  part  cycle  is  comparison  temperature.  in  all  40.07%.  turbomachine  significant  is  of  conventional cycle  The  resulting  efficient  efficiency  intercooled  •  most  include  cycles  Atmospheric  also of  be gas  cycles but  load  cycle,  was  PFB  systems  outside  the  f,luidized  could two  bed  be  classes combined  included. reheat may not  in be  both  of  air  beneficial  considered  performance  the  the  in  this  intercooled  heater to  and  cycle  study. steam  tube  60  cycle  could  The  design  be  made  turbine  part  including the  studied.  load more  modelling precise  of with  the  air  heater  better  cycle  estimates  could of  the  improved  by  efficiency.  Variations The  be  of  load  the  air  heater  modelling  the  turbomachine  film  technique  property  maps.  cycle  can could  be be  calculations  studied.  and  improving  61  BIBLIOGRAPHY  1.  M u k h e r j e e , D . K . , " P r e s s u r i z e d F l u i d i z e d Bed Combustor C y c l e A s s e s s m e n t " , The P r o c e e d i n g s of the 7th International C o n f e r e n c e on F l u i d i z e d B e d C o m b u s t i o n , O c t o b e r , 1982.  2.  M o s k o w i t z , S . , W a l k e r , W . , " S t a t u s Report of the Wood-Ridge PFB P i l o t P l a n t " , The P r o c e e d i n g s of t h e 7 t h International C o n f e r e n c e on F l u i d i z e d B e d C o m b u s t i o n , O c t o b e r , 1982.  3.  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Engineers  Transfer",  "Energy  Thermodynamics",  5th  Handbook",  Ed.,  Technology  "Heat  and  Tables",  4th  Exchanger  2nd  Ed.,  Physics"  Handbook",  2nd  52nd  Ed.,  The  1976.  McGraw  Design",  Wiley &  64  Table  1 -  Published  Research Group  Cycle Description  Curt i ssWright (22)  Air  S - L , AEP & DBA (5)  Heater Cycle  Intercooled Steam Tube 1 FW H e a t e r  Oak Ridge Nat i o n a l Lab.  Preheated Steam Tube 2 FW H e a t e r s  Foster Wheeler (29)  Supercritcal Steam Tube  Brown/ Bover i  (1 )  Gilbert/ Commonwealth (6) '  Cycle  Analysis  Ef f ic i e n c y Gross Net  4 0 . 0%  PFB Pressure  Turbine Temp  7  Bar  871 ° C  39.7%  40.7%  16  Bar  832°C  39.2%  41.2%  10  bar  800°C  10  Bar  927°C  10  Bar  848°C  7  Bar  871 ° C  40.5%  Steam Tube Cycle  4 1.4%  Air  37.5%  Heater Cycle  Steam Tube Cycle  40 . 5%  41.2%  Air  38.2%  39.0%  Heater Cycle  Results  65  Table  2 -  Equilibrium Dissociation  Combust i o n Product  Ni trogen Carbon D i o x i d e Oxygen Water N i t r i c Oxide Hydroxyl Radical Atomic Oxygen Carbon Monoxide Hydrogen Atomic Hydrogen  Table  3 -  Anderson  Creek  Ca/S Mole  Ratio  Product  Concentrations  Concentrat ion  73.3 % 13.0 % 7.7 % 5.9 % 52 ppm 0 . 2 ppm < 1 ppb < 1 ppb < 1 ppb << 1 ppb  Limestone  Sulphur  Sulphur Retention  2: 1  66 %  4: 1  81.5%  6:1  86 %  8:1  89 %  10:1  90 %  Retention  (13)  66  Table  Cycle Description  4 -  Steam  Ef f ic i e n c y (Gross) %  Tube  Cycle  Performance  S p e c . Work A i r Base MJ/kg  Criteria  , S p e c . Work Steam Base MJ/kg  GT P o w e r Fract ion %  Basic Cycle  38.7  0 . 928  1 .839  17.8  Preheat  38.8  0.927  1 .832  23.0  Intercooling (single)  40. 1  0.961  1 .962  24.4  Intercooling (double)  39.8  0.955  1.998  18.4  Feed Water Heating  39.2  0.940  1 .553  17.5  Intercooling & FWH  40.3  0.959  1.710  22.4  67  Table  5 -  Effect  of  C o a l T y p e on Performance  PFB C o m b i n e d  Cycle  C r e e k Hat I l l i n o i s Hat C r e e k Hat C r e e k Hat Creek #6 Coal (Dry, (As Ash F r e e ) (Dry) Received) (Washed) Ultimate Analys i s 66.4% 4.5% 7.5% 2.7% 1 . 3% 5.8% 11.7%  30.8% 2.4% 10.6% 0.4% 0.8% 22.5% 32.5%  37.6% 3.1% 13.5% 0.6% 0.8% 10.0% 34.3%  39.7% 3.1% 13.7% 0.5% 1 .0%  Intercooled Steam  40.62%  39.36%  40.07%  40.56%  40.72%  Air Heater Cycle  38.44%  36.39%  37.53%  37.95%  38.17%  C H 0 S N H20 ASH  68.4% 5.3% 23.6% 0.9% 1 .8%  41.9%  Gross Effic'cj  Table  6 -  Comparison  of  Power  Generation  Interc :ooled Ste ?am Cyc : l e T u r b i ne Inlet Temp. Gross Ef f ' cy  Net Ef f ' c y  Fuel .  800°C  38.0  Hat  AJ. r He£ i t e r Cyc : l e  900°C  40.07 %  %  Creek  41.29  %  39.2  %  Coal  Efficiencies  Pulver. Coal Boiler  870°C  900°C  37.53 %  38.29 %  35.7  (Washed)  %  36.4  %  38.18  %  36.0 %  68  Steam T u r b t n e s  Pump  Figure  1 -  Rankine  Cycle  69  Figure  2 -  Brayton  Cycle  Figure  3 -  Temperature/Entropy and  Rankine  Diagrams Cycles  for  the  Brayton  Combustor  Figure  4 -  Oil  Fired  Combined  Cycle  Plant  Schematic  Figure  Pressurized  Fluidized  Bed  Coal  Combustor  Figure  6 -  Air  Heater  PFB Combined  Cycle  C o a x i a l Heat Exchange  Steam  Turbines Generator  Hot Gas VF11trat i o n  H.P. T u r b i n e / Compressor  03 C  ro  5  Steam Drum  rt  ^ 1  fD DJ  3  -3 C rjfD  L.P. T u r b i n e / Compressor  PFB  ^ W O O  3  tr  o *~< o t—•  fD  J Heater V  J  )1 1 I  T  Condenser  Ash Cooler  Air Inlet Power T u r b i n e / Generator  3 fD  a  V Combus istors  ISuper-  Economiser  P«™P  76  Read Steam D a t a (Fundamental Steam Equation Parameters) Read Des i gn P a r a m e t e r s ( T u r b 1 n e I n l e t Temp, Combustor Pressure. Ambient, and Steam C o n d i t i o n s )  Gas  System  Calculate Compressor Inlet and Air Properties  Outlet  Est imate C o - a x i a l Heat Exchange In t h e PFB D u c t i n g Ca1culate Combust i o n R e a c t 1ons, PFB H e a t Exchange, and Gas P r o p e r t i e s C a l c u l a t e H.P. T u r b i n e Gas P r o p e r t i e s  t h e H.P. Outlet  the  Inlet  Calcu1 ate T u r b 1 n e work a n d Gas P r o p e r t i e s  Est imate L.P. T u r b i n e and E c o n o m i s e r O u t l e t Gas P r o p e r t i e s  Ca1cu1 a t e t h e S t a c k G a s Dew P o i n t , Econom i s e r Out 1et T e m p e r a t u r e . and P r e s s u r e Drop a c r o s s t h e Econom1ser  NO  I  Figure  9 -  Steam  Tube  Cycle  Analysis  Flow  Chart  77  Steam  System  Calculate Steam T u r b i n e Inlet, Reheater Inlet, L.P. Steam T u r b i n e Inlet. Condenser I n l e t and O u t l e t , Economiser I n l e t , B o i l e r Inlet, and S u p e r h e a t e r Inlet Steam Properties H.P.  Steam  Total  Ca1culate Massflow and P r e s s u r e  Heat,  Ca1culate work a n d  Drops  Efficiency  Wr i t e Thermodynamic P r o p e r t l e s . C o m p o n e n t Work, a n d E f f i c i e n c y  78  Start  Read Steam D a t a (Fundamenta 1 Steam Equation Parameters) Read D e s i g n P a r a m e t e r s ( T u r b i n e I n l e t Temp, Combustor Pressure, Ambient Condi t i o n s , a n d Steam Conditions)  Gas  System  Calculate Compressor I n l e t and O u t l e t Air Properties Calculate PFB and Estimate  Combustion Reactions. Heat Exchange, Gas P r o p e r t i e s the Cooling  A i r Flow  Calculate Cooling A i r Temperature at t h e PFB O u t l e t a n d Air/Gas Mixture Properties a t t h e H.P. T u r b i n e Inlet  Re-Estimate the C o o l i n g A i r Mass Flow  yes  Calculate H.P. T u r b i n e w o r k a n d O u t l e t Gas P r o p e r t i e s  L.P.  Estimate T u r b i n e a n d HRSG O u t l e t Gas P r o p e r t i e s  Calculate S t a c k G a s Dew P o i n t . E c o n o m i s e r O u t l e t Temperature, and Pressure Drop a c r o s s t h e Econom1ser  Figure  10 -  A i r Heater  Cycle  Analysis  Flow  Chart  79  Steam  System  Calculate Max ifflum S u p e r h e a t T e m p e r a t u r e w i t h a n HPSG E f f e c t i v e n e s s o f 8 0 % Calculate B o i l e r Pressure which results 1n a n 8 8 % S t e a m Turbine Exhaust O u a l i t y  Ca1culate B o i 1 e r , C o n d e n s e r , a n d Pump I n l e t and O u t l e t Conditions C a l c u l a t e t h e Gas P r o p e r t i e s t h r o u g h t h e HRSG  Reduce  the B o i l e r  Pressure  Re-Estimate the 5team Mass Flow  YES  Total  Heat,  Calculate Work, a n d  Efficiency  Wr 1 t e Thermodynamic P r o p e r t ies, C o m p o n e n t Work, a n d Efficiency  Stop  600  P E R C E N T O F TOTAL HEAT T R A N S F E R Figure  11 -  Boiling  Pinch  Point  in  Generator  a  Heat  Recovery  Steam  C o a x i a l Heat Exchange  Steam T u r b i n e s Generator  H.P. Turbine/ Compressor  3  Hot Gas Fi 1 t r a t i o n  Steam Drum SuperHeater  V  L.P. Turbine/ Compressor  PFB Combustors  Condenser  Air  -E3-  Inlet  Power Turb i ne/ Generator  Stack  Recuperator  Economiser  Pump  Coaxial Heat Exchange  iQ C  Steam Turbines Generator  Hot Gas Fi1trat ton  H.P. Turbine/ Compressor  w  rt fD OJ  5  Ol  Steam (S14) Drum  3 -3 C  cr ro  o o  *<  SuperHeater  <S1  L.P. Turbine/ Compressor  PFB Combustors Condenser  ro Feed Water Heater  rr £T O  D  ro  Power Turbine/ Generator  Ash  Air Inlet  Cooler Stack  fD fD  a CU rt fD  X  fD  CU rr fD  i-l  _ j  Economi ser  ~o Pump  CO  40.5  Figure  15  -  Efficiency  of  the  Basic  Steam  Tube  Cycle  40.5  Figure  16  - Effect  of  Intercooling Performance  on  Steam Tube  Cycle  CD  Legend Basic Cycle X  Recuperated Cycle Intercooled Cyc 1 e I n t e r c o o l e d and Recuperated C y c l e  i  1  1.2  1.8  1.4  COMBUSTOR PRESSURE M P a  Figure  17 -  Effect  o f R e c u p e r a t i o n on Performance  Steam  Tube  Cycle  Figure  18  -  E f f e c t of  Feed  Cycle  Water  Heating  Performance  on  Steam  Tube  Figure  19  -  Intercooled  Steam  Tube  Cycle  Performance  89  ©+- —  -©  Gas  h Gas  10 .  Turbine Compressor  Steam  85.0  86.0  Turbines  87.0  88.0  90.0  89.0  TURBINE E F F I C I E N C Y % Figure  20 - E f f e c t  of T u r b o m a c h i n e  Intercooled  ••20.0  Steam  40.0  Tube  60.0  Efficiency Cycle  21  - Effect  100.0  80.0  INTERCOOLER EFFECTIVENESS Figure  on t h e  %  o f I n t e r c o o l e r E f f e c t i v e n e s s on t h e  Intercooled  Steam  Tube  Cycle  90  12.0  14.0  16.0  1B.Q  20.0  BOILER PRESSURE (MPA) Figure  22 - E f f e c t  of B o i l e r Steam  Pressure  Tube  i  on t h e I n t e r c o o l e d  Cycle  r  525.0 530.0 535.0 540.0 545.0 550.0 STEAM SUPERHEAT TEMPERATURE ( • Figure  23 - E f f e c t  o f Steam S u p e r h e a t Steam Tube C y c l e  on t h e I n t e r c o o l e d  91  T  o.o  2.0  4.0  10.0  6.0  REHEAT PRESSURE (MPA)  Figure  24  -  Effect  of  Steam  Reheat  Tube  i  on  1  1  i  5.0  AMBIENT' TEMPERATURE 25  -  Effect  of  Intercooled  Intercooled  Cycle  -5.0  Figure  the  r  15.0  25.0  (•  Ambient Temperature Steam  Tube  Cycle  on  the  Steam  92  I  I  Q.B  I  I  .1  L  0.9  Q.B5  26  -  Effect  of  Ambient  Steam  i  i  1  n  25.0  i  i  1 1 30.0  Pressure  Tube  i  L  1.0  0.95  AMBIENT PRESSURE (MPA) gure  I  1.05  IX10-1) on  the  Intercooled  Cycle  i i  1 1 35.0  1 1 40.0  1 1 r 45.0 50.0  CONDENSER. TEMPERATURE (C) Figure  27  -  Effect  of  Intercooled  Condenser Steam  Temperature  Tube  Cycle  on  the  93  i 0.0  Figure  28  - Effect  20.0  40.0  1  1 60.0  r  80.0  • 100.0  EXCESS AIR. %  of E x c e s s Tube  A i r on Cycle  the Intercooled  Steam  /  *  Legend \  \  X  X  850 C 0  1  0.8  1.2  1.4  1.6  COMBUSTOR PRESSURE MPa  Figure  29  - A i r Heater  Cycle  800 C  Performance  900 C  Figure  30  -  Effect  of  Heater  Gas  Turbomachine  Cycle  Efficiency  Performance  on A i r  96  in _  5^ °" UJ  LO  _J  T  80.0  Figure  31  -  81.0  32  Effect  -  T  T  B3.0  84.0  85.0  STEAM TURBINE EFFICIENCY %  25.0  Figure  B2.0  of  Steam T u r b i n e Heater  Cycle  35.0  40.0  30.0  Efficiency  45.0  on  the  Air  50.0  CONDENSER TEMPERATURE (C)  Effect  of  Condenser Heater  Temperature  Cycle  on  the  Air  41  Intercooled Steam Tube Cycle  >O LJ  y  39  LJ  UJ  I O  o  3 8  00  o cr  o  COAL  37-^  O  I l l i n o i s #6 Hat Creek (Washed) Hat Creek (As Received)  36 1  2  1.5  C O M B U S T O R  Figure  33 -  Comparison  of  P R E S S U R E  Cycle  Different  2.5  M P a  Performance  Fuels  with  Three  98  5 4.5 4r-  3.5H  <. Cr:  ZD m m  Ld  cr:  3-  \  Legend  2.5-  Q_  21.5\  1+0.3  0.4  0.5  —1  0.6  1  1  0.7 0.8  0.9  1.1  REDUCED M A S S F L O W  Figure  36  -  Axial  Compressor  Performance  Map 1  A  N*=1.0  X  N*=0.9  Q  N*=0.8  g|  N*«=0.7  S  N*=0.6  ^  N*=0.5  N*=Reduced  Speed  Legend $  N*=1.0  ©  N*=0.9  O  N*=0.8  +  N*=0.7  O  N*=0.6  ffl N*=0.5 Reduced Speed  Figure  37  -  Axial  Compressor  Performance  Map 2  Figure  38  -  Turbine  Performance  Map 1  1  Legend V  N*=1.0  (Sa N*=0.8  0.60 H  1  2  1.5  Figure  39  -  2.5  3  3.5  PRESSURE RATIO Turbine  Performance  Map 2  0  N*=0.6  A  N*=0.4 N* = Reduced Speed  103  Figure  40  -  A i r Heater  Cycle  Part  Chart  ^  Start  Read D e s i g n Data (Design operating C o n d i t i o n s , Heat Exchanger s i z e s ) Read Bypass A i r Percentage  Gas  System  Calculate Compressor I n l e t P . T . H . S E s t i m a t e A1r Massflow, Compressor Shaft Speed, and Bed Temperature  Calculate Compressor C h a r a c t e r i s t i c s : E f f i c i e n c y and P r e s s u r e R a t i o Ca1culate Compressor O u t l e t  P.T.H.S  S p l i t o f f Bypass and Cool 1ng A i r  C a l c u l a t e PFB Combustion and R e q u i r e d Heat Removal by Cool 1ng A i r Calculate Heat T r a n s f e r to C o o l i n g A i r  Load Cycle  Analysis  Flow  1 04  Mix t h e C o m b u s t i o n Gases with the C o o l i n g A i r and Bypass A i r and C a l c u l a t e Turbine I n l e t Condi t i o n s  Ca1culate Temperature and Pressure o f H.P. T u r b i n e E x h a u s t  Ca1cu1 a t e H.P. T u r b i n e Efficiency  Characteristics and Mass Flow  Calculate Gas I n l e t  t h e HRSG T.P.H.S.Cp  1 05  Steam  System  Calculate Outlet Estimate and  the Condenser Conditions Steam  Superheat  Massflow  Temperature  Calculate t h e Bo i 1 e r P r e s s u r e f r o m t h e Steam T u r b i n e C h a r a c t e r i s t i c s Calculate S u p e r h e a t e r Heat T r a n s f e r and S u p e r h e a t e d Steam Temperature  y  Has  Xtn«a rp<srn»si t \ y r f Temperature \ Changed /  NO  \ Feed and  Calculate W a t e r Pump Conditions the Conditions at the Onset of B o i 1 i n g  Ca1cu1 a t e the Heat T r a n s f e r from the Combustion Gases Calculate t h e Gas Temperatures Corresponding to the Boiling Saturation points the S t a c k Ent r a n e e  and  Redistribute the Heat T r a n s f e r Areas and R e - E s t i m a t e t h e Steam Mass Flow  VES  J_ Calculate  The  Cycle  Performance  Wri t e Thermodynamic Properties. C o m p o n e n t Work, a n d Effldency  r  -i  10  20  1  30  1  40  1  50  1  i  60  70  i  80  I  90  100  S Y S T E M LOAD (PERCENT O F DESIGN LOAD)  Figure  41  -  Part  Load  Performance  of  Air  Heater  i  Cycle  160  JOT  155  UJ  D  150  or  Z>  % UJ CL  / 145-  UJ P  O  /  •  140-  Legend LJ  Stack Gas Temperature Dew Point  135 -r 0  10  Figure  20  30  40  50  60  70  80  90  100  SYSTEM LOAD (PERCENT OF DESIGN LOAD) 42  -  Variation  of  Point  Stack With  Gas Load  Temperature  a n d Dew  108  APPENDIX  List Air  Of  A -  COMPUTER  SUBROUTINES  Routines  Thermodynamics  Subrout ine  I nput Parameters  Output Parameters  AIR  P,T,M  H,S,Cp,p  AI RH  P,H,M  T,S,Cp,p  AIRS  P,S,M  H,T,Cp,p  Gas  Thermodynamics  Subroutine  and  Combustion  I nput Parameters  Output Parameters  GAS  P,T,M  H,S,Cp,p, Dew P o i n t  GASH  P,H,M  T,S,Cp,p, Dew P o i n t  GASS  P,S,M  H,T,Cp,p, Dew P o i n t  GAHS  H,S,M  P,T,Cp,p, Dew P o i n t  109  Gas  Thermodynamics  BED (Combust i o n )  and  Combustion  I n l e t H,M Outlet T,P Excess A i r Coal Analysis % Coal Burned Ca/S Mole Rat  MIX  Gas P , H , M Air P,H,M  cont.  Outlet M,S,H, Cp,p,Dew Point C o o l a n t Heat Transfer Solids Cooler Heat Transfer  T,H,M,Cp,p  1 10  Water  and  Subrout ine  STATET  Steam  Thermodynamics  Valid Regions  Everywhere except the 2 Phase Reg.  I nput Parameters  P,T  H,S,Cp,X,p  STEAM (L=2)  Vapor  STEAM (L=3)  Liquid  P,T  H,S,Cp,X,p  Everywhere  P,H  T,S,Cp,X,p  STATEH  P,T  Output Parameters  H,S,Cp,X,p  INTEH  Vapor  LIQH  Liquid  P,H  T,S,Cp,X,p  STATES  Everywhere  P,S  T,H,Cp,X,p  P,H  T,S,Cp,X,p  INTES  Vapor  LIQS  Liquid  VATS  Vapor  T,S  P,H,Cp,X,p  VATH  Vapor  T, H  P,S,Cp,X,p  P,S  P,S  T,H,Cp,X,p  T,H,Cp,X,p  111  Water  and  Steam  PSAT  T  <  647.25 K  TSAT  P  <  2 2.1  SATCON  These  input  thermodynamics load  Thermodynamics  analysis), INPUT:  T < P <  647.25 K 2 2 . 1 MPa  and  output  library. the  Fluid  MPa  In  Saturat ion Temperature  Saturat ion Pressure  Saturat ion Pressure  S a t u r a t i on Pressure  P,T (Saturat ion)  Hf,Hg,Sf,Sg  parameters the  following  Velocity,  cont.  heat  are  the  transfer  parameters  Tube  for  are  Diameter,  short  library  (for  part  added:  and  Heat  Transfer  Mode. OUTPUT:  Viscosity,  Reynolds  Thermal  number,  and  Conductivity,  Heat  Transfer  Prandtl  number,  Coefficient.  )  11 2  APPENDIX  Pure  B -  THERMODYNAMIC AND T R A N S P O R T  Component  Enthalpy  Property  h=8.31 4 ( a + b T + c T : + d T 3 + e T " ) B e n s o r1 S o u r c e : I<.S.  a  b  -1029.7 -1 030 . 7 -1153.9 -1175.0 -1077.4  2  CO 2 H20 NO  Formulations  (kj/kmol)  Gene; r a l E q u a t ], o n : T i r1 K e l v i n  o  PROPERTIES  c  3.344 3 . 253 3.096 3.743 3.502  (30) e  d  2.943E-4 6.524E-4 2.730E-3 5.656E-4 2.994E-4  1 . 953E-9 -6.575E-12 - 1 . 495E-7 1.539E-11 8.660E-11 -7.885E-7 4.952E-8 -1.818E-11 -9.590E-9 -4.904E-12  Generai l E q u a t i o rI : h = 4 l 8 6 . c3 (a + b r + c r 2 - r d r 3 + e r q ) Raw d a t a s o u r c e : Jei n a f T a b l e s5 ( 3 1 ) T=T/ ' 1 0 0 0 . 0  S02 S03  a  b  -2.2956 -2.73  5.600 5.519  Equation: Generai l T i n ? ^e l v i n  CaC03 CaSO„ Si02 A1203 Fe203 CaO MgO Coal  Heat  8.2162 14.2107  -4.1531 -7.2269  h=4.184(a+bTH- c T 2 + d / T ) S o u r c e : CI.E. H a n d b o o r1 b  c  -7463.8 -7066.9 -8138.1 -8722.5 -9499.6 -3557.3 -3989.8  19.68 18.52 17.09 22.08 24.72 10.0 10.86  0. 005945 0.010985 0.000227 0.004485 0.00802 0.000559 0.000599  h=141.5(T-298.0)  of  d  a  Formation Hf 0  CO 2 H20 NO S02 S03 CaC03 CaSO„  c  -393522 -241827 90417 -297040 -396030 -1211268 -1403816  T  (kj/kmol) Source (9) (9) (32) (32) (32) (32) (32)  in  Kelvin  e 0.8615 1.4769  (32) d 307600 156800 897200 522500 423400 108000 208700  11 3  Specific  Heat Cp  (kj/kmol  K)  G e n e r a l EE q u a t i o n : C:p=a + b£?k.+cc?m+dt? ) cSource: 0=T/1 00 Van Wylerl & Sc>nntag (9) n  a  b  39.060 37.432 -3.7357 143.05 59.283  N o2 CO 2 H 0 NO 2  2  k  -512.79 0.02010 30.529 -183.54 -1.7096  c  m  1072.7 -178.57 -4 . 1034 82.751 -70.613  -1.5 1 .5 0.5 -0.25 0.5  i rl  d  -2.0 -1.5 1 .0 0.5 -0.5  -820.4 236.88 0.02420 -3.6989 74.889  Genera i l E q u a t i o n : Cp=4.1868(a+h5 r + c r + d r ) Rav* d a t a s o u r c e J a n a f T a b l eis T=T/1()00.0 2  a S0 S0  b  5.8257 -2.73  2 3  Entropy  (kj/kmol  3  c  15.509 5.519  2  2  2  3  b  152.692 166.61 9 167.043 144.602 171.329 197.977 195.207  2.9751 -7.2269  K) 3  2  o2 C0 H 0 NO S0 S0  (31 ) d  1 1 . 2842 14.2107  Gene; r a l Equate.on: s=a+b-• + C T + d r + e Raw d a t a s o u r c e : J ci n a f T = T/'1 000. 0 a  -3.0 -2.0 2.0 1. 0 -1.5  178.36 173.96 199.38 200.38 179.93 215.22 253.37  T a b l e s5 (31)  c  d  e  -192.85 -180.07 -168.11 -209.50 -192.14 -185.76 -181.85  1 19.242 110. 388 92.482 128.447 1 18.696 101.649 85.576  -29.3123 -27.3588 -21.4962 -31 . 2672 -29.3130 -23.4504 -17.5878  Vi scosi ty S u t h e r ' l a n d E q u a t i c>n: M=a/(T+b) ( T / c ) ' T i n }t e l v i n 1  a AIR H 0 N o2 C0 2  2  2  0.00669 0.00843 0.01911 0.02319 0.02149  b 117.9 659.0 109.17 129.68 246.88  5  c 273. 15 273. 1 5 573. 15 573. 1 5 573 . 1 5  Source (34) (34) (33,34) (33,34) (33,34)  11 4  Thermal  Conductivity  Genera i l Equation: r=T/1()00.0  k =(a + b r + c T ) / ' 1 0 0 . 0 2  a AIR H 0 N2  0.33017 -0.3226 0.64962 0 . 12902 -0.9856  2  o CO  2  2  Heat  1) Nu=  Transfer  Forced  2) Nu=  Forced  Nu=  Nu=  - P r ° '  6  - P r ° '  0 . 0 6 - ( p  £  (Evaluated  / p  over 6  Tube  Bundles  9 2  Bundles  ) ° '  with  Kreith  in  a  Bubbly  -Pr (36)  Transfer  v  Tubes  7  Tube  Zakkay  Heat  in  (35)  over  0.05-Re°'  Source:  .AV. .G. .G. . G. .G.  (35)  Kreith  Convection  Boiling  -1.813 2.375 -0.3438 -1.2919 -1.6333  3 3  Convection  Source:  4)  8  Convection  Kreith  0 . 3 3 - R e ° '  5 +  Source  Coefficients  0 . 0 2 3 - R e ° '  Source:  3)  8.265 6.7469 6.4950 8.6943 9.3511  Turbulent  Source:  c  b  2  8  inside  - R e  the (35)  0  '  8  7  Tubes  - P r ° '  liquid  4  properties)  PFB  1 15  Mixture  Calculations  Enthalpy hm=  {Zryh^/m  Specific Heat Cp = Iy.-Cp. Entropy m  s  =  {  ( Z n i * s i ^ " R'Uryln  y  i  ) } / m  '  R , l n  (p/p0)  Viscosity Thermal Conductivity km = i k./a * 1 J ( i c ) - ( y 1 / y j ) >  -{l+Ca./a^^CMj/M.)^}  Cp Specific Heat Notation: h Enthalpy k Thermal Conductivity s Entropy m Mass R Gas Constant M Molecular Weight Viscosity y Subscripts i m 0  Component i Mixture Standard Conditions  2  /" { / M l + ^ / M j ) ) * } 1  1 16  Hat  Creek  Ash A n a l y s i s  Hat  Creek  Ash  and  Enthalpy  Analysis:  Component  Concentrat ion  Si02 A1203 Fe203 CaO MgO S03  Enthalpy  with  Ash and  Enthalpy of Si02 (kJ/kg)  TEMP  300 400 500 600 700 800 900 1000 1100 1 200 1 300  of  K K K K K K K K K K K  Correlation  -0.0 63.9 147.6 241 . 3 341 . 0 444.4 550 . 4 658.4 767.9 878 . 5 990.2  The E n t h a l p y of Hat a 4% c o r r e c t i o n .  58.6% 30.7% 6.4% 1 .6% 1 . 3% 1 .4%  Si02  at  Various  Enthalpy of Ash (kJ/kg)  0.5 72. 1 159.4 255. 5 357 . 1 463.0 572 . 1 684 . 1 798. 5 915.2 1 034 . 0  Creek  ash  of  Temperatures:  Enthalpy Si02 +4% (kJ/kg)  0.0 66.5 153.5 251 . 0 354.6 462.2 572 . 4 684.7 798.6 913.6 1029.8  was  thus  Error (kJ/kg)  -0.5 -5.6 -5.9 -4.5 -2.5 -0.8 0.3 0.6 0. 1 -1.6 -4.2  modelled  by  Si02  11 7  Acid  Dew P o i n t  Form _ u— l—a t i o n  (  T h e f o l l o w i n g f o r m u l a t i o n f o r t h e a c i d dew p o i n t a s a f u n c t i o n o f s u l p h u r t r i o x i d e c o n c e n t r a t i o n was d e v e l o p e d f r o m L i s l e a n d Sensenbaugh data (15), u s i n g a l e a s t square fit.  T  =  114.9 T  in  [S03]  so  +  6.5l3-Log[S03]  +  0.4052•(Log[S03])2  Kelvin -  Concentration  of  S03  in parts  (ppm)  Dew P o i n t T e m p e r a t u r e ( K ) Data Equat ion Error  0.70 0.40 2.0 3.0 4.0 11.0 26.0 60. 200 . 400 .  373 . 2 383 . 2 393.2 394 . 3 399.3 405.4 413.2 422. 1 433.2 442 . 2  3  373.6 382. 4 392 . 4 395.7 397 . 8 406. 1 413.6 421.5 433 . 9 441 . 6  0.4 -0.8 -0.8 1 .4 -1.5 0.7 0.4 -0.6 0.7 -0.6  per  million  1 18  APPENDIX  Coal  Hat  and S o r b e n t  Creek  Coal:  C -  COMBUSTION  Analyses  As R e c e i v e d  and M o l a r  Heat Heat  Hat  of. of  Creek  Coal:  2.5643 2.381 0.6625 0.01246 0.05711 1 . 2489 0.5409  11555.0 -554590.7  Partially  Washed  U l t imate Analys i s  Carbon Hydrogen Oxygen Sulphur Ni t rogen Moi s t u r e Ash  Heat Heat  of of  # Moles P e r 100 k g of C o a l  30.8% 2.4% 10.6% 0.4% 0.8% 22.5% 32.5%  Combustion Formation  Combustion Formation  Compositions  (37)  Ultimate Analysis  Carbon Hydrogen Oxygen Sulphur Nitrogen Moi s t u r e Ash  CALCULATIONS  kJ/kg kJ/kmol  (As  per  CURL  # Moles P e r 100 k g of C o a l  37 . 6% 3.1% 13.5% 0.64% 0.8% 10.0% 34.3%  15100.0 -325537.0  3.29682 3.07448 0.84539 0.01995 0.05709 0.55491 0.57063  kJ/kg kJ/kmol  specifications  13)  11 9  Hat  Creek  Coal:  Dry  U l t imate Analys i s  Carbon Hydrogen Oxygen Sulphur Nitrogen Ash  Heat Heat  Hat  of of  Creek  39.7% 3.1% 13.7% 0.5% 1 .0% 41 .9%  Combustion Formation  Coal:  Dry and Ash Free  Carbon Hydrogen Oxygen Sulphur Ni trogen  of of  Combustion Formation  3.3088 3.0723 0.8548 0.01608 0.07369 0.69794  14909.7 -254978.4  Ultimate Analysi s  Heat Heat  # Moles P e r 100 kg of C o a l  kJ/kg kJ/kmol  (DAF)  # Moles P e r 100 kg of C o a l  68.4% 5 • 3 *6 23.6% 0.9% 1 .8%  25677.8 -439085.7  5.6984 5.2911 1.4722 0.02769 0.12691  kJ/kg kJ/kmol  1 20  Illinois  #6  Coal  (38)  U l t imate Analysi s  Carbon Hydrogen Oxygen Sulphur Nitrogen Moi s t u r e Ash  Heat Heat  of of  Anderson  6 6 . 4% 4.5% 7.5% 2.7% 1 . 3% 5.8% 11.7%  Combustion Formation  Creek  # Moles P e r 100 kg of C o a l  Limestone  Component  Moi s t u r e CO 2 CaO MgO Si02 A1203 Fe203 Na20 K20 S03 CI  5.5282 4.504 0.47127 0.08421 0.09424 0.32195 0.19472  27703.0 -165915.0  kJ/kg kJ/kmol  (13)  Concentration  0.2% 42.2% 53.0% 0.4% 2.7% 0.8% 0.2% 0.07% 0.03% 0.06% 0.01%  121  Combustion  Calculations  Nomenclature: Combustion AirMF (N2 ) i  C o m b u s t i o n a i r mass f l o w # mol of n i t r o g e n i n a i r flow # M o l e s of Oxygen i n c o m b u s t i o n a i r flow # Moles of Coal required for a given air fuel ratio (1 m o l = 100 k g ) # mol of Sorbent required for a g i v e n C a / S mol r a t i o  (02)i  (Coal) (CaC03)i  Coal  Reactants  Composition  Cf Hf Of Sf Nf K2Of ASH f  # # # # # # #  M o l e s o f C a r b o n i n 100 kg o f c o a l M o l e s o f H y d r o g e n a t o m s i n 100 k g o f c o a l M o l e s o f O x y g e n a t o m s i n 100 kg o f c o a l M o l e s o f S u l p h u r i n 100 kg o f c o a l M o l e s o f N i t r o g e n a t o m s i n 100 k g o f c o a l m o l o f W a t e r i n 100 kg o f c o a l M o l e s o f A s h i n 100 kg o f C o a l  Combustion 7 Ca/S BU SRF  Parameters  Air Fuel Ratio C a l c i u m t o S u l p h u r atomic mol r a t i o F r a c t i o n of c o a l burned in combustion (Combustion Efficiency) Sulphur Retention Factor: f r a c t i o n of s u l p h u r c a p t u r e d by s o r b e n t  Combustion  Products  (N2) (C02 )  # mol of # mol of  nitrogen in combustion gases Carbon Dioxide i n combustion gases mol of water vapor i n c o m b u s t i o n gases o f m o l o f SOx i n c o m b u s t i o n gases of mol of S u l p h u r D i o x i d e i n combustion gases of mol of Sulphur T r i o x i d e i n combustion gases of mol of unspent Sorbent in solids di sposal of mol of spent Sorbent in solids di sposal of mol of Coal Ash i n s o l i d s disposal of mol of unburned c o a l i n s o l i d s di sposal  (H20) (SOx) (S02 )  # # #  (S03 )  #  (CaC03)  #  (CaSO«)  #  (Ash) (UBcoal)  # #  1 22  Combustion  Reactants  Oxygen (0 )i  =  2  AirMF-0.007279  Nitrogen (N )i  =  2  Fuel  AirMF-0.027383  Consumption  (Coal) = ( 0 2 ) 1 / Y • {Cf + Hf/4 - Of/2 + Sf + Nf/2)  Sorbent  (CaC0 )  (CaC0 )  =  3  Gaseous  (Coal)-Sf-Ca/S  Products  Nitrogen (N ) 2  =  Combustion  Products 2  Dioxide  (C0 )  =  Water  Vapour  (H 0)  =  2  Of  ( N ) i + (Coal)-Nf-BU/2  Carbon 2  Consumption  3  (Coal)  Emissions •  [Cf.BU+Sf-SRF]  (Coal)«BU«[Hf/2+H 0f] 2  123  Sulphur  Gases  (SOx)  =  (Coal)-Sf•[BU-SRF]  (S03) (S02)  = =  (SOx) (SOx)  SK/M+SK] (S03)  • -  SK = K S 0 2 • /{(0 2 )/ZProducts> K  S0 2  =  e x  P  { 9  -  8 4 7  x = T/1000  - 16.339'T + 4.727-r } 2  T i n Degrees K  Oxygen (02)  =  (02)i+(Coal)-BU-[Of/2-Hf]-(C02) -(CaSO,)/2-(S02)-1.5-(SO3)  Solid  Products  Calcium  Carbonate  (CaC03)  =  Calcium (CaSO„)  (Unspent  Sorbent)  (Coal)-Sf•[Ca/S-SRF]  Sulphate =  (Coal)-Sf-SRF  Ash  (From b u r n e d c o a l  (Ash)  =  (Coal)-BU-ASHf  Unburned  Coal  (UBcoal)  =  (Coal)•(1-BU)  only,  and  includes  fly  ash)  124  Equilibrium The  following  concentrations combustion the  main  of  was  Calculations  computer 10  program  combustion  temperature,  four  assumption the  Combustion  calculates  products.  it  was  assumed  constituents  did  not  supported  by  the  that  change  results  Due the  the to  equilibrium the  low  concentration  significantly.  and  greatly  of  This  simplified  calculations. "Combustion" Fuel:  Dry Ash Free Hat Creek N i t r o g e n and S u l p h u r . Excess A i r : 40% Temperature: 825°C Pressure: 1.6 MPa  Coal  neglecting  1 2  IMPLICIT REAL*8 (A-H,0"Z) R E A L * 8 K , L , M , N , K A , K B , K C , K D , K E , K F , , X ( 1 0) , C C ( 1 0) , N 2 I ,LAMBDA  3 4 5 6 7 8  T=825.+273.15 P=1.6 CN=5.523 HM=5.038 00=1.770 LAMBDA=1.4  Dissociation A B C D E F Set 9 10 11 12  the  gas  Reactions: C 0 2 = CO + H 2 0 = OH + H20 = H2 + NO = 1 / 2 N 2 H 2 = 2H 0 2 = 20 constant  and  1/20Z 1/2H2 l/202 +l/202  the  fuel  and  air  RM0L=8.314 N2I=0.0273832 021=0.007278884 FUEL=02I/LAMBDA/(CN+HM/4-00/2)  C a l c u l a t e the primary r e a c t i o n CO 2 13 K=CN*FUEL H20 14 L=HM/2*FUEL 02 15 M=02I+FUEL*00-K-L/2 N2  products:  mass  flows:  125  15  N=N2I Calculate react ion  16 17 18 19 20 21 22  15  the  equilibrium constants  for  each  dissociation  KA=DEXP(DLOG(T)**(-5.94324)*(-3794l00)+15.4408) 1*DSQRT(0.1013/P) KB=DEXP(DLOG(T)**(-5.7 522)*(-27 53082)+14.871) 1*DSQRT(0.1013/P) KC=DEXP(DLOG(T)**(-5.6888)*(-2131245)+12.6313) 1*DSQRT(0.1013/P) KD=DEXP(DLOG(T)**(-5.8503)*(-l036137)+3.3483)  23  KE=DEXP(-115.54+0.10221*T~0.00002644*T*T)*(0.1013/P)  24  KF=DEXP(-131.34+0.11641*T-0.00003018*T*T)*(0.1013/P) Calculate  25  total  number  of  primary  products  S=K+L+N+M Calculate  26  the  the  degree  of  reaction  completion  A=K*KA*DSQRT(S/M)  27 B=DSQRT(L/KC*(KB**2)*DSQRT(M*S)) 28 C=KC*DSQRT(S/M)*L-B/2 29 D=KD*DSQRT(N*M) 30 E=DSQRT(S*KE*(C+B/2))/2.0 n R TP(rSo* d 31 D i s s o c Fi a= tDi So Q KuFc* t( sM: - D / 2 ) ) / 2 . 0 1 CO 2 2 CO 3 H20 4 H2 5 02 6 N2 7 NO 8 OH 9 H 1 0 O Calculate 32 33 34 35 36 37 38 39  the  number  of  X(1)=K-A X(2)=A X(3)=L-B-C X(6)=N-D/2 X(7)=D X(4)=C+B/2 X(5)=M+(A+C-D)/2 X(8)=B  moles  of  each  constituent  126  40 41  42  X(9)=2*E X(10)=2*F C a l c u l a t e t o t a l number o f products SUMX=X(1)+X(2)+X(3)+x(4)+X(5)+X(6)+X(7)+X(8)+X(9)+X(1 Calculate  43 44 4 5 231 46 47  the  product  concentrations  DO 231 1 = 1 , 1 0 CC(I)=X(I)/SUMX CONTINUE STOP END  Equilibrium  Calculation  Results  Combustion a i r : Nitrogen in a i r flow: Oxygen i n a i r f o l w : Fuel consumed:  1 kg 0 .02738 0 .00728 0 .00088  Reaction  Equilibrium Ka Kb Kc Kd Ke Kf  Degree  of  0.304 0.261 0.307 0.219 0.332 0.297  reaction A B C D E F  Constants: E-09 E-1 0 E-09 E-03 E- 1 6 E-18  completion  0 . 535 0.715 -0.357 0 . 1 94 0.874 0.281  E-1 1 mol E-08 mol E-08 mol E-05 mol E-1 5 mol E - 1 1 mol  kmol kmol kmol  or  0.088  kg  1 27  Dissociation  Products  kmol o f Product  co2  CO H20 H2  o2  N2 NO OH H 0  0.487 0.536 0.222 0.246 0.286 0.274 0 . 194 0.715 0.175 0.563  E-02 E- 1 1 E-02 E-1 1 E-02 E-01 E-05 E-08 E-14 E-11  Product Concentrat ion 0 . 1 30 0.143 E-09 0.0595 0.660 E-10 0.0766 0 . 733 0.0000521 0.192 E-06 0.468 E-13 0.151 E-09  1 28  Heat  Loss  Typical N2 02 Coal  0.7335 0.1950 0.0302  C02 H20 02 N2  of  to  Heat Heat  of of  Heat  lost  Heat  lost  Heat  of  3.02  kg  products  9990  kJ/kg  Available  in  combustion  production  of  CO  by  of  Lost= =  Percent  CO a n d NO  moi moi moi moi  Formation Formation  Quantity Heat  of  reaction  Combustion  Heat  lost  moi moi moi or  primary  0.1304 0.0595 0.0766 0.7335  Total  Heat  Production  reactants  Typical  Heat  in  the  of of  CO: C02:  -110.5 -393.5  = =  9990 30.2  ( 50 - 1 0 6 14 k J  ppm  kmol)-(283.0  of  total  heat  to  production  Formation  @ 50  of  production  of  :  of  50•106  C02:  kmol  MJ/kmol)  =  0.05%  NO  NO:  90.4  MJ/kmol  Q u a n t i t y o f NO p r o d u c e d Ci 250 ppm : 250 - 1 0 6 Heat Lost= (250-10s k m o l ) - ( 9 0 . 4 MJ/kmol) = 20 k J Percent  of  total  heat  •  MJ/kmol MJ/kmol  f o r m a t i o n o f CO i n l i e u 283.0 MJ/kmol  CO p r o d u c e d  kJ/kg MJ  production  =  0.07%  kmol  3.02kg  1 29  APPENDIX  D -  Pressure Heat PFB Bed  COMPONENT PERFORMANCE  Losses  through  FORMULATIONS  AND DATA  Equipment  Exchangers Combustor side  Boiler  pressure  pumping  Superheater Reheater  drop:  4 5 KPa  (5,18)  power:  pumping  pumping  Negligible  power:  power  :  Wp=1.0% o f (13,39)  Wp=2.8% o f  Heat  Transfer  Heat  Transfer  (13,29)  Heat  Recovery  Steam Gas  side  side  Steam  pumping  pressure  Generator power: drop:  Wp=0.15% o f T u r b i n e Power (13) kJ/kg P=0.4% p e r 100 (2)  Economiser Water Gas  side  side  pumping  pressure  power: drop:  Transfer Wp=0.10% o f H e a t (13) P=3.3% p e r 100 kJ/kg  I ntercoolers Water Air  side  side  pumping  pressure  power:  Negligible  (13)  drop:  P=3.0% p e r (13,20)  100  kJ/kg  100  kJ/kg  Recuperators Air  side  pressure  drop:  P=2.4%  Gas  side  pressure  drop:  P=7% p e r (39)  Feed All  Water  Heaters  pressure  drops  negligible  (18)  per  100  kJ/kg  1 30  Auxiliary Hot  Gas  Equipment  Clean  Pressure  Up  Equipment  drop:  P=2.5%  of  Combustor (18) •  Pressure  Duct ing Gas  Compressor  to  Turbine: P=2% o f  Combustor (1,18)  Pressure  131  Performance Gas  Air  Tube C y c l e :  Heater  Cycle:  7? =  Heater  Cycle:  i? = 88%  The f o l l o w i n g tube cycles.  Pressure Rat i o  turbine  (19)  92.6~4.6-Pc  (%)  (20,29)  (18,20)  efficiency  14.6  Steam < >  Oak  88.3%  data  was  Tube  Cycle  1 0 1 0  7?  =  T? =  to  Gas  0 .75 0 .88  the  following  Turbine +  compiled  for  Ridge National Laboratory (18)  Stal-Laval  fitted  was  Source  80% 81% 83% 85% 88% 88%  This  data  Ef f ic i e n c y  3 4 5 7 1 0 >1 0  P P  n = 86%  Turbine  Air  steam  Turbomachinery  Compressor  Steam  Gas  of  0.018-P  GT120  formulations:  Efficiency: -  Turbine  0.0005-P2  20  the  1 32  Steam The ( 13,21 )  Turbine  following  Pressure MPa Steam  Tutje  Cycle  Cycle  2.62 0 . 38  500 . 0  89.5  32. 1 17.9  84.2 82.8  v  Heater  Cycle:  7? =  Feed  Water  =  V  0.46% 0.47%  89.5% 80 . 35 + 0 . 000 1 • ( S u p e r h e a t  Pumps  Pump:  Paras i t ic Losses  (21 )  Cycle:  Water  compiled.  ( 1,5)  Tube  Feed  were  Ef f i c i e n c y  385 245  Steam  efficiencies  Power MW  540  H e a t e>r  Air  turbine  Temperature Deg C  14.00 Air  steam  =  (18)  Temp)  1 33  Auxiliary  Power  Turbomachine Gas  Losses  for  Steam T u r b i n e Steam tube c y c l e : Air heater cycle:  Handling  Calculations  Efficiency  Miscellaneous  0.25%  of  gas  2% o f 3% o f  steam steam  system  power  turbine turbine  power power  Losses  Coal Crushing Sorbent Crushing Coal & Sorbent handling Ash D i s p o s a l  Alternator  Efficiency  Losses  Turbine:  Materials  Net  Losses  23.4 46.0 52.4  kJ/kg kJ/kg kJ/kg  coal sorbent solids  61.1  kJ/kg  ash  98.5%  0.2%  of  total  power  1 34  APPENDIX  Selected Basic Gas  Steam  System  G1 G2 G5 G7 G8 G1 0 Gl 5 Gl 6 Gl 7 G21  Steam Tube  Cycle  STEAM T U B E  CYCLE  RESULTS  Results  Cycle  Data:  Pressure 0.1008 0.4884 1.6000 1.6000 1 . 5550 1.481 6 0.6262 0.2611 0 . 1087 0.1013  Steam  System  SI S3 S4 S5 S6 S7 S8 S9 SI 4  Pressure 16. 0000 3 . 5001 3. 2959 0. 0067 0. 0067 1 7 . 5964 1 7 .4 8 6 8 1 7 . 0395 1 7 . 0394  Temp 1 5 . 00 206.54 418.64 544.35 900.00 800.00 632 . 1 7 481.57 352.25 166.85  Enthalpy -12.07 186.35 414.03 552.71 -1482.44 -1608. 1 7 -1814.59 -1994.50 -2144.58 -2351.88  Cp 1.0127 1.031 3 1 .0835 1.1133 1.2742 1.2542 1.2148 1.1727 1.1317 1 . 0726  Entropy 6.8589 6.9184 6.9646 7 . 1450 7.6448 7.5440 7.5754 7.6077 7.6406 7.2690  Data: Temp Enthalpy 3409.95 540 . 0 0 3 1 7. 3 2 3022.77 540 . 0 0 3543.69 38 . 32 2398.00 38 . 3 2 160.55 39 . 8 3 182.34 66 . 2 6 291.69 173 . 7 7 744.61 352 . 5 2 2545.08  A i r Flow = 1 .0000 Gas F l o w = 1.1030 F u e l Flow =0.1589 Ash Flow = 0.0686 Lime Flow = 0.0127 B o i l e r Flow= 0.5048 Bed Heat = Ash Heat = Economi ser Heat =  E -  kg/s kg/s kg/s kg/s kg/s kg/s  1608.54 55.21  kJ/s kJ/s  228.65  kJ/s  Entropy 6 . 446 6 . 524 7 . 301 7 . 733 0 . 550 0 . 563 0. 899 2 . 058 5 . 1 74  Density 47.753 14.004 8.969 0.0 992.864 999.868 987.299 903.720 120.177  Cp 2 .802 2 . 561 2 . 265 0 .0 4 . 1 76 4 . 1 34 4 . 1 50 4 . 324 1 8. 3 3 7  Cycle Efficiency = T o t a l Heat = T o t a l Work = P o w e r T u r b i n e Work= S t e a m T u r b i n e Work= Pump Work = Power Turbine Contribution  •=  38.70 2 3 9 9 . 111 1 928 38 165.54 773 84 11 00  kJ/s kJ/s kJ/s kJ/s kJ/s  17.83 %  135  Steam Gas  G1 G2 G3 G4 G5 G7 G8 Gl 0 G1 5 G1 6 G1 7 G21  System  Cycle  with  Intercooling  (single)  Data:  Pressure 0.1008 0.4884 0.4678 0.4678 1 .6000 1 .6000 1 . 5550 1 .4816 0.7847 0.3402 0.1087 0.1013  Steam  SI S3 S4 S5 S6 S7 S8 S9 SI 4  Tube  System  Pressure 1 6. 0 0 0 0 • 3 . 5001 3 .2959 0 . 0067 0 . 0067 1 7. 8 7 7 5 1 7. 4 7 8 5 1 7. 0 3 9 4 1 7. 0 3 9 4  A i r Flow = Gas F l o w = F u e l Flow = Ash Flow = Lime Flow = B o i l e r Flow-  Temp 15.00 206.54 71 . 9 6 71 . 9 6 236.29 365.72 900.00 800.00 673.98 524.60 352.69 166.85  Enthalpy -12.07 186.35 46.20 46.20 217.78 356.47 -1482.44 -1608.17 -1763.74 -1943.63 -2144.09 -2351.88  Cp 1.0127 1 .0313 1.0146 1.0146 1.0378 1.0701 '1.2742 1.2542 1.2254 1.1854 1.1318 1.0726  Entropy 6.8589 6.9184 6.5917 6.5917 6.6398 6.8798 7.6448 7.5440 7.5667 7.5973 7.6414 7.2690  Data: Temp 5 4 0 . 00 3 1 7 . 32 5 4 0 . 00 3 8 . 32 3 8 . 32 3 9 . 85 1 3 5 .51 2 4 2 . 08 3 5 2 . 52  1 . 0000 1.1 030 0.1589 0.0686 0.0127 0.4900  Bed H e a t = 1412.30 Ash Heat = 55.21 I ntercooler Heat = 140.15 Economi ser Heat = 229.20  Enthalpy 3 4 0 9 . 95 3 0 2 2 . 77 3 5 4 3 . 69 2 3 9 8 . 00 1 6 0 . 55 1 8 2 .68 581 . 34 1 0 4 9 . 05 2 5 4 5 . 09  kg/s kg/s kg/s kg/s kg/s kg/s kJ/s kJ/s kJ/s kJ/s  Entropy 6.446 6 . 524 7.301 7.733 0.550 0.564 1 .675 2.692 5.174  Density 4 7 . 753 1 4 . 004 8 . 969 0. 0 9 9 2 . 864 9 9 9 . 977 9 3 9 . 057 8 2 4 . 597 1 2 0 . 1 76  Cp 2 .802 2 .561 2 .265 0 .0 4 . 1 76 4 . 133 4 .230 4 . 636 1 8. 3 3 7  Cycle Efficiency = T o t a l Heat = T o t a l Work = Power T u r b i n e W o r k Steam T u r b i n e WorkPump Work = Power Turbine Contribution  =  40.07 2399.11 961.42 221.10 751.17 10.85  23.00  kJ/s kJ/s kJ/s kJ/s kJ/s  1 36  Steam Gas  G1 G2 G3 G4 G5 G6 G7 G8 Gl 0 G1 5 Gl 6 Gl 7 G1 8 G21  Tube  System  wi t h  Intercooling  a n d J_ F e e d  Water  Heater  Data:  Pressure 0 . 1 008 0. 4884 0 . 4678 0 . 4678 1 . 6000 1 . 6000 6000 1 . 5550 1 . 4816 0 . 7847 0 . 3402 0 . 1 087 0 . 1 087 0 . 1013  Steam  S1 S3 S4 S5 S6 S7 S8 S9 SIO S1 1 S 12 S1 4  Cycle  Temp 1 5.00 206.54 71 . 9 6 71 . 96 236.29 236.29 365.72 900.00 800.00 673.98 524.60 352.69 352.69 166.85  System  Pressure 16. 0000 3 . 5001 3. 2959 0 . 0067 0 . 0067 9 . 04 1 0 8. 6416 8 . 2018 8. 2039 8. 2039 1 7 . 0394 1 7 . 0393  Enthalpy -12.07 186.35 46.20 46.20 217.78 217.78 356.47 - 1482.44 - 1 6 0 8 . 17 -1763.74 -1943.63 -2144.09 -2144.09 -2351.88  Cp 1 .0127 1.0313 1.0146 1.0146 1.0378 1.0378 1.0701 1.2742 1.2542 1.2254 1.1854 1.1318 1.1318 1.0726  Entropy 6.8589 6.9184 6.5917 6.5917 6.6398 6.6398 6.8798 7.6448 7.5440 7.5667 7.5973 7.6414 7.6414 7.2690  Data: Temp Enthalpy 540 . 00 3 4 0 9 . 95 3 1 7 . 32 3 0 2 2 . 77 5 4 0 . 00 3 5 4 3 . 69 3 8 . 32 2 3 9 8 . 00 3 8 . 32 1 6 0 .55 1 7 1 . 76 3 9 . 09 1 3 4 . 87 572 . 68 24 1 .10 1 0 4 3 . 06 2 9 6 . 81 1 3 2 6 . 27 4 3 2 . 75 3 2 2 3 . 65 301 . 07 1 3 4 1 . 35 3 5 2 . 52 2 5 4 5 . 09  A i r Flow= 0000 Gas Flow= 1 030 F u e l Flow = 1 589 Ash Flow= 0686 Lime Flow= 0127 B o i l e r Flow= 5600 Feed Water Heater Bleed Flow = 0.0727 Bed Heat= 1412.30 Intercooler Heat= 140.15  Ent ropy 6 . 446 6 . 524 7 . 301 7 . 733 0 . 550 0 . 557 1 . 677 2 . 701 3 . 223 6 . 477 3 . 228 5 . 1 74  Mass 0 . 560 0 . 487 0 . 487 0 . 487 0 . 487 0 . 487 0 . 487 0 . 487 0 . 560 0 . 073 0 . 560 0 . 560  Dens i t y 47 . 753 1 4 .004 8 . 969 • 0. 0 9 9 2 . 864 9 9 6 . 512 9 3 5 . 073 8 1 7 . 1 65 7 1 8 . 962 2 7 . 883 727 . 927 1 2 0 . 1 76  kg/s kg/s kg/s kg/s kg/s kg/s  Cycle Efficiency T o t a l Heat = T o t a l Work = P o w e r T u r b i n e Work= S t e a m T u r b i n e Work= Pump W o r k  kg/s  Power T u r b i n e Contribution  kJ/s kJ/s  Ash Heat= Economi ser Heat=  55.21 229.20  40.33 2399.11 967.66 221.10 760.47 13.90  22.85 kJ/s kJ/s  2 2 2 0 4 4 4 4 5 2 5 18  Cp .802 . 561 . 265 .0 . 1 76 . 1 53 .252 .712 .664 .655 .431 .337  kJ/s kJ/s kj/s kJ/s kJ/s  1 37  Net  Efficiency  of  the  Case  Turbine Inlet Temp  I n t e r c o o l e d Steam  1  800°C  Combustor Pressure Fuel  2  1 . 6 MPa  3  900°C  1.6 MPa  1 . 6 MPa  Illinois  Cycle Case  800°C  Hat C r e e k Washed  Gross Work  Case  Tube  #6  Hat Creek Washed  961.43  kj  961.88  kJ  990.50  kJ  Alternator Losses  14.42  kj  14.43  kj  14.86  kJ  Materials Handling  17.48  kj  11.83  kj  17.48  kJ  15.57  kj  15.96  kJ  15.30  kJ  1.92  kj  1.89  kJ  1.98  kJ  44.39  kj  44.11  kJ  49.62  kJ  912.04  kj  917.77  kJ  940.88  kJ  Turbomachine Losses Mi sc . Losses  Total losses  Net Work  '  Net Ef f i c i e n c y  38.0 %  38.8 %  39.2 %  1 38  APPENDIX  Air  Gas  System  G1 G5 G7 G8 G9 G1 0 G1 2 G1 3 G1 5 G1 8 G20 G2 1  System  Pressure 0.0067 1.5657 1.5657 1.5657 0.0067  F u e l Flow = Ash Flow = Lime Flow = B o i l e r FlowBed Heat Ash Heat HRSG H e a t  Cycle  A I R HEATER  Results  CYCLE  (Design  RESULTS  Load)  Data:  Pressure 0 . 1008 0.7000 0.7000 0. 6550 0.6221 0.7000 0.6221 0.6221 0.2434 0 . 1 029 0.1013 0.1013  Steam  51 52 53 55 56  Heater  F -  = = =  Temp 15.00 251.45 251.45 900.00 900.00 251.45 851.36 870.00 6 6 9 . 13 507.97 240.69 157.1 1  Enthalpy -12.07 233.87 233.87 -1482.44 -1482.44 233.87 9 0 2 . 19 34.92 -202.67 -388.09 -684.23 -773.67  Mass 2.930 2.930 1 .000 1 . 103 1.103 1 .930 1 .930 3.033 3.033 3 . 033 3.033 3.033  Cp 1.0127 1 . 041 4 1.0414 1 . 2742 1 . 2742 1.0414 1 . 1 709 1.2082 1 . 1 702 1 . 1 325 1.0592 1 . 0395  Entropy 6.8589 6.9090 6.9090 7.8889 7.8889 6.9090 7.7837 7.8581 7.8931 7.9254 7.4731 7.2834  Data: Temp 38.32 38.45 200.37 414.04 38.32  Enthalpy .160.55 162.48 854.11 3285.18 2419.78  0.1589 0.0686 0.0127 0.3922  kg/s kg/s kg/s kg/s  1289.70 55.21 1224.57  kJ/s kJ/s kJ/s  Entropy 0.550 0.551 2.334 7.293 7.803  Quality 0.0 0.0 0.0 1.000 0.937  Cp 4.176 4.172 4.495 2.169 0.0  Cycle Efficiency = Total Heat T o t a l Work P o w e r T u r b i n e Work= S t e a m T u r b i n e Work= Pump Work Power Turbine Contribution  37.53 % 2399.11 kJ/ 900.43 k J / 562.33 k J / 339.37 k J / 1 .27 k J /  62.45 %  1 39  Air  Heater Part Load S i m u l a t i o n 90 MV? M o d u l e : D e s i g n L o a d A n a l y s i s Gas  System  Pressure 0 . 1008 0 . 7000 0 . 7000 0 . 6550 0 . 6221 0 . 7000 0 . 6221 0 . 6221 0 . 2432 0 . 1 029 0 . 1013 0 . 1013 0 . 1013  G1 G5 G7 G8 G9 G1 0 G1 2 G1 3 G1 5 G1 8 G1 9 G20 G21  Steam  SI S2 S3 S4 S5 S6  Temp Enth'py 15.0 -12.07 251 . 5 233.87 251.5 233.87 900.0 -1466.35 900.0 -1466.35 251 . 5 233.87 850. 1 900.73 869.2 40.21 668.3 -197.43 507.4 -382.49 453.7 -443 . 1 0 236.8 -682.08 1 57. 1 -767.32  System  Pressure 0.0067 1.5657 1.5657 1 . 5657 1.5657 0.0067  Heat  Data:  Temp Enthalpy Entropy 38.32 160.55 0 . 550 38.45' 162.48 0.551 200.37 854 . 1 1 2 . 3 3 4 200.37 2793.42 6.430 414.04 3 2 8 5 . 19 7.293 38.32 2419.79 7.803  Exchanger  Flow  Area  26.55 15.88  0. 0. 0. 0. 0. 0.  4520 1 543 6799 71 59 2977 7 1 73  89.22 88.49 89.00 89.29  0 . 41 50 0 . 291 1 0 . 2456  HT C o f  208.11  Cp 4 . 1 76 4 . 172 4 . 495 2 .799 2 . 1 69  HT  Coef  1783.26 43935.61 390.77 260.89  Flow  Area  0.0009 0.0011 0.0047 0.0074  Data:  Efficiency = T o t a l Heat = T o t a l Work = P o w e r T u r b i n e Work S t e a m T u r b i n e Work Pump Work = Dew P o i n t  Cp Ent'py 1.013 6.86 1.041 6.91 1 .041 6.91 1 .274 7.89 1 .274 7.91 1 .041 6.91 1.171 7.78 1 .208 7.86 1.170 7.89 1.132 7.93 7.85 1.118 1 . 058 7.47 1 .039 7.29  Data:  HT C o e f (U) 19.2550 kJ/(s-m2 69.8169 k j / ( s - m 2 88.5654 kJ/(s-m2 84.8983 kJ/(s-m2  PFB H e a t E x c h a n g e r HRSG S u p e r h e a t e r HRSG B o i l e r HRSG W a t e r H e a t e r  Acid  Mass 2 .930 2 .930 1 .000 1 . 1 02 1 . 1 02 1 .930 1 .930 3 .032 3 .032 3 .032 3 .032 3 .032 3 .032  =  = =  3 6 . 82 2399 . 1 883 . 4 561 . 2 323 . 4 1 .2  143.6°C  F u e l Flow =0.1589 B o i l e r Flow- 0.3737 Bed Heat = 1287 . 0 3  kg/s kg/s kg/s  %  kJ/s kJ/s kJ/s kJ/s kJ/s  •K) •K) •K) •K)  HT S u r f a c e 0.2864 m2 0 . 0 1 6 4 m2 0 . 0 7 3 2 m2 0 . 0 4 3 7 m2  1 40  75  % LOAD  Gas  G1 G5 G7 G8 G9 G1 0 G1 2 G1 3 G1 5 G1 8 G1 9 G20 G2 1  0 0 0 0 0 0 0 0 0 0 0 0 0  System P (MPa) .1008 .6247 .6247 . 5858 .5613 .6247 .5613 .561 3 .21 92 . 1 023 .1013 .1013 .1013  Steam  S1 S2 S3 S4 S5 S6  T (C) 1 5 . 00 2 2 9 . 07 2 2 9 . 07 8 7 5 . 54 8 7 5 . 54 2 2 9 . 07 835. 1 2 7 5 0 . 20 5 6 3 . 59 4 3 3 . 28 3 9 5 . 07 213. 1 2 1 5 3 . 71  System  P 0 . 0067 1 . 1 758 1 . 1 758 1 . 1 758 1 . 1 758 0 . 0067  Ef f i c i e n c y  38. 38. 187. 187. 375. 38.  =  T o t a l Heat = T o t a l Work = Power T u r b i n e Steam T u r b i n e Pump Work = Acid  Data:  Dew P o i n t  H (kJ/kg) - 1 2 . 07 210. 1 5 210. 1 5 - 1 4 9 7 . 28 - 1 4 9 7 . 28 210. 1 5 8 8 3 . 33 5 0 . 92 - 1 6 5 . 09 -312. 1 4 - 3 5 4 . 64 - 5 5 2 . 87 - 6 1 6 . 05  M (kg) 2 .31 34 2 .3134 0 .7895 0 .8704 0 .8704 1 . 5238 1 . 5238 2 .8906 2 .8906 2 .8906 2 .8906 2 .8906 2 .8906  Cp (kJ/kgC) 1.0127 1.0362 1.0362 1.2692 1.2692 1.0362 1.1683 1.1809 1.1413 1 . 1 084 1 . 0980 1.0488 1.0359  S 0.5500 0.5508 2.2078 6.5305 7.3095 7.7792  X 0.0 0.0 0.0 1 .0 1 .0 0.9341  7.8150 7.7573 7.4145 7.2761  h (kJ/sm2  239. 22. 13.  89. 82. 84. 86.  Data: T  H 1 6 0 . 55 1 6 2 . 00 794 . 59 2784. 1 3 3 2 0 9 . 69 2 4 1 2 . 49  32 42 08 08 98 32  34.53 %  Work Work  =  S (kJ/kgC) 6.8589 6.8958 6.8958 7.8974 7.9095 6.8958 7.7960 7.7489 7.7842  = =  1894.2 654.2 425.1 229.9 0.8  142.7°C  F u e l Flow = 0.1254 B o i l e r Flow= 0.2884 Bed H e a t = 1025.80  kg/s kg/s kJ/s  kJ/s kJ/s kJ/s kJ/s kJ/s  4. 4. 4. 2. 2.  Cp 1 756 1 726 4359 6342 1 385  h 1454 . 37585. 302 . 206.  141  5_0 % LOAD Gas  G1 G5 G7 G8 G9 G1 0 G1 2 G1 3 G1 5 G1 8 G1 9 G20 G21  0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0.  System P 1 008 5432 5432 5091 4918 5432 4918 4918 1 932 1 022 1013 1013 1013  Steam  SI S2 S3 S4 S5 S6  0. 0. 0. 0. 0. 0.  T 1 5 . 00 204 . 47 2 0 4 . 47 8 4 9 . 27 8 4 9 . 27 204 . 47 8 1 8 . 24 6 2 8 . 44 4 5 9 . 00 3 6 3 . 93 338 . 47 1 9 0 . 08 1 4 7 . 91  System  P 0067 8345 8345 8345 8345 0067  Ef f i c i e n c y  H - 1 2 . 07 1 84. 1 6 184. 1 6 - 1 5 3 0 . 36 - 1 5 3 0 . 36 184. 1 6 8 6 3 . 78 5 8 . 04 - 1 3 3 . 81 -239. 1 0 - 2 6 6 . 98 - 4 2 6 . 92 - 4 7 1 . 52  =  Dew P o i n t  F u e l Flow = B o i l e r Flow = Bed H e a t =  M 2 . 6381 1 . 7240 0 . 5884 0. 6486 0. 6486 1. 1 356 1. 1 356 2. 6983 2 . 6983 2 . 6983 2 . 6983 2. 6983 2. 6983  H 160. 161. 728. 2770 . 3125. 2405.  55 58 88 92 97 32  S 0. 5500 0 . 5506 2. 0636 6. 6484 7 . 33 1 5 7 . 7562  30.90 %  Work Work  =  Cp 1.0127 1.0309 1.0309 1.2640 1.2640 1.0309 1.1656 1.1510 1.1108 1.0854 1.0785 1. 0 4 0 3 ' 1.0320  6 6 6 7 7 6 7 7 7 7 7 7 7  S .8589 .8832 .8832 .9073 .91 70 .8832 .81 58 .6326 .6683 .6999 .6585 .3608 .2601  h  286. 18. 10.  89. 75. 78. 82.  Data:  T 38.32 38.39 172.20 172.20 333.37 38.32  T o t a l Heat = T o t a l Work = Power T u r b i n e Steam T u r b i n e Pump Work = Acid  Data:  = =  1411.6 436.2 284.1 152.6 0.5  140.6°C  0.0935 0.2117 771.77  kg/s kg/s kJ/s  kJ/s kJ/s kJ/s kJ/s kJ/s  X 0 .0 0 .0 0 .0 1.0 1.0 0 . 931 2  4 4 4 2 2  Cp . 1 756 . 1734 . 3802 .4812 . 1 070  h 1134. 30844. 224 . 1 55.  1 42  Gl G5 G7 G8 G9 G1 0 G1 2 G1 3 G1 5 G1 8 G1 9 G20 G21  30  % LOAD  Gas  System  0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0.  p 1 008 4625 4625 4309 4 1 88 4625 4188 41 88 1 685 1 020 1013 1013 1013  Steam  S1 S2 S3 S4 S5 S6  0. 0. 0. 0. 0. 0.  T 1 5 . 01 1 7 9 . 30 1 7 9 . 30 8 2 3 . 41 8 2 3 . 42 1 7 9 . 30 800 . 37 5 2 6 . 18 3 7 6 . 22 3 1 6 . 93 298 . 66 1 7 2 . 22 1 4 0 . 60  System  p 0067 6072 6072 6072 6072 0067  Efficiency  =  Dew P o i n t  F u e l Flow = B o i l e r Flow = Bed Heat =  H - 1 2 . 06 1 5 7 . 70 1 5 7 . 70 - 1 5 6 2 . 79 - 1 5 6 2 . 79 1 5 7 . 70 843. 1 3 5 7 . 02 - 1 0 9 . 69 - 1 7 4 . 42 - 1 9 4 . 22 - 3 2 9 . 44 - 3 6 2 . 73  M 2. 3950 1 . 2539 0. 4279 0 . 4718 0 . 4718 0. 8259 0. 8259 2. 4388 2 . 4388 2 . 4388 2 . 4388 2 . 4388 2 . 4388  H 1 6 0 . 55 1 6 1 . 29 6 7 2 . 63 2757.. 36 3061 . 87 2 4 0 4 . 80  S 0 . 5500 0 . 5504 1 . 9360 6 . 7561 7 . 3674 7.7546  25.49 %  Work = Work =  =  Cp 1.0127 1.0259 1.0259 1.2588 1.2588 1.0259 1.1627 1.1240 1.0857 1.0697 1.0648 1.0342 1 .0286  6 6 6 7 7 6 7 7 7 7 7 7 7  S .8589 .8727 .8727 .9244 .9324 .8727 .8424 . 5388 . 5739 . 61 49 . 5832 .3171 . 2398  h  349. 14. 8.  89. 67. 72. 76.  Data:  T 3 8 . 32 3 8 . 37 1 5 9 . 33 1 5 9 . 33 300 . 20 3 8 . 32  T o t a l Heat = T o t a l Work = Power T u r b i n e Steam T u r b i n e Pump Work = Acid  Data:  1026.7 261.7 157.9 104.1 0.3  138.7°C  0.0680 0.1585 566.12  kg/s kg/s kJ/s  kJ/s kJ/s kJ/s kJ/s kJ/s  X 0 .0 0 .0 0 .0 1 .0 1 .0 0.9309  Cp 4.1756 4 . 1740 4.3390 2.3702 2.0815  h 899. 25421. 171. 1 20.  143  Net  Efficiency  of  the  Case Turbine Inlet Temp Combustor Pressure Fuel  Gross Work  A i r Heater  1  cycle  Case  2  Case  3  870°C  870°C  900°C  0 . 7 MPa  0 . 7 MPa  0 . 7 MPa  Hat Creek Washed  Illinois  #6  Hat C r e e k Washed  900.43  kJ  910.43  kJ  918.52  kj  Alternator Losses  13.51  kJ  13.66  kJ  13.78  kJ  Materials Handling  17.48  kJ  15.96  kj  17.48  kJ  11.59  kJ  11.64  kJ  12.07  kj  1.80  kJ  1.82  kj  1.84  kJ  44.38  kj  43.08  kJ  45.17  kJ  856.05  kJ  967.35  kJ  873.35  kJ  Turbomachine Losses Mi sc . Losses  Total losses  Net Work  Net Ef f i c i e n c y  35.7 %  36.6 %  36.4 %  1 44  APPENDIX  G -  PULVERIZED  COAL  BOILER ANALYSIS  RESULTS  The o p e r a t i n g c o n d i t i o n s and p r e s s u r e d r o p s were a P u l v e r i z e d Coal B o i l e r design completed i n 1969 f o r utility. Two b o i l e r feed water h e a t e r s are i n c l u d e d , in the r e q u i r e d b o i l e r i n l e t t e m p e r a t u r e of 250°C. Cycle Gas  System  Analysis  S1 S3 S4 S5 S6 S7 S8 S9 S 1 0 SI 1 SI 2 S 1 3 SHI  System  Pressure 16. 8930 4 . 1 849 4. 0130 0. 0067 0. 0067 0 . 4114 0 . 4114 4 . 1 097 4 . 1 097 4 . 1 849 0 . 4114 18. 0650 18. 0650  Press 0.1013 1013 1013 0969 1013  Temp 15.00 218 328, 161 1 67,  00 00 57 84  Enthalpy -12.07 198.44 •2575.44 •2762.28 • 2 7 5 5 . 40  Cp 1.0127  Entropy 6.8575  1.0337 1.1339 1.0789 1.0808  7.3965 7.5955 7.2449 7.2481  Data: Temp 537 . 80 3 3 0 . 35 5 3 7 . 80 3 8 . 32 3 8 . 32 3 8 . 35 1 44 . 66 1 4 5 . 27 2 5 2 . 00 3 3 0 . 35 2 4 2 . 36 2 5 6 . 46 3 5 7 . 33  Air Flow1 .0000 Gas F l o w 1.1217 Fuel Flow0 . 1878 Ash F l o w 0.081 1 Lime F l o w 0.0150 B o i l e r Flow = 0.9194 #1 F e e d W a t e r H e a t e r Bleed Flow= 0.183 #2 F e e d W a t e r H e a t e r Bleed Flow= 0.118 SHI  Results  Data:  Air Inlet Air Preheater Outlet / Boiler Inlet Boiler Outlet Preheater Outlet Fan Outlet  Steam  taken from a Canadian resulting  = Superheater  Enthalpy 3 3 9 3 . 48 3 0 3 7 . 54 3531 . 67 2 3 6 7 . 87 1 6 0 . 55 1 6 1 . 05 609. 1 6 614. 1 1 1 0 9 5 . 08 3 0 3 7 . 54 2 9 4 8 . 03 1 1 1 6 . 58 2 5 0 5 . 71  kg/s kg/s kg/s kg/s kg/s kg/s kg/s kg/s Inlet  Entropy 6 . 403 6 . 473 7 . 1 98 7 . 636 0 . 550 0 . 550 1 . 787 1 . 789 2 . 81 1 6 . 473 7 . 335 2 . 819 5 . 098  Mass 0 . 919 0 . 737 0 . 737 0 . 618 0 . 618 0 . 618 0 . 737 0 . 737 0 . 919 0 . 182 0 . 1 18 0 . 919 0 . 919  Density 51 . 0 0 0 1 6. 5 4 2 1 1. 005 0. 0 992 . 8 6 4 993 .031 92 1 . 9 4 7 923 . 463 796 . 2 2 7 0 .0 1 .756 805 . 4 9 5 1 34 . 645  Cycle Efficiency 38. Total Heat = 2835. T o t a l Work = 1084. S t e a m T u r b i n e Work == 1 1 1 5 . Pump Work 31 .  Cp 2 . 855 2 . 627 2 . 290 0. 0 4 . 1 76 4 . 1 75 4 . 299 4 . 289 4 . 873 0. 0 2 . 062 4 . 743 2 3 . 1 19  24 31 25 69 44  %  kJ/s kJ/s kJ/s kJ/s  145  Net  Efficiency  Fuel:  Hat  of  Creek  Gross  PCB C y c l e Coal  (Washed)  Work  Gross'Efficiency  Alternator  Losses  Materials Flue  Gas  Steam  Total  Net  Net  1082.64  kJ  38.2 %  16.24  kJ  Handling  7.07  kJ  Scrubbing  16.24  kJ  Turbine  22.28  kJ  Losses  62.23  kJ  1020.41  kJ  Work  Efficiency  36.0 %  146  APPENDIX  H -  GAS  TURBOMACHINE  CHARACTERISTIC  Axial Compressor Characteristic Equations P = 1 +  2  °_Y  • { 2p-(M*/a)" 2 - ( M * / a ) p }  p = 4 + 3.5-(N*2'98) 6 = 1.224.(N*2'51) a = N* - 0.2  n  =  . { B . M * / e - (M*/e)6 } y = { 0.75 + 0.19-/N* - 0 . 8 7 - N * 1 0 ' 7 5 } .TLJ/0.831 6 = 3.9 + 0.011-exp{8N*} e = 1.1-N* - 0.13  Turbine C h a r a c t e r i s t i c Equations M* = 1.002 - exp{-a-i|j}  a = 2.11 + 4.25.(1+N*) K, = 3 - ( P - l ) / ( P - l )  2  d  n : C - A*(^~ " *) - w { l - e x p ( - * / 2 ) } 2  1  C = n d +0.0078 X = exp{6.332«N* - 8.6} a) = exp{ -0.5 - 7 . 1 « ( N * ' ) } 2  M* = M . / r / p o  N* = N / A  Q  Q  32  EQUATIONS  1 47  APPENDIX  Listings l i b r a r i e s are  I  -  COMPUTER  PROGRAMS  of the f o l l o w i n g main programs included in this Appendix.  INTERCOOLED  STEAM T U B E  CYCLE  (Design  AIR  HEATER  CYCLE  (Design  Load)  AIR  HEATER  CYCLE  (Design  Load  and  subroutine  Load)  Analysis  for  Part  Load  Simulation) AIR  HEATER  PULVERIZED SUBOUTINE  CYCLE COAL  (Part POWER  LIBRARY  Load PLANT  (Long  Simulation) (Design  Version  for  Load) Part  Load  Simulation)  '  I n t e r c o o l e d Steam Tube Cycle  2  Design Load Analysis  3  4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60  C  C  IMPLICIT REAL*8(A - H,0 - 2) REAL'S TG(21). PG(21). HG(21), SG(21). MG(21). CPG(21). LMT3, NGT, 1 NGC. NP. NT. NI. MF. MST1, MST. LAMBDA, MU. KT, MSOL. 2 MLIME, PS(15). TSI15). HS(15). SS(15). XS(15). CPS(15). 3 FAG(21). FAS(15). HTS(15), PCS(15). PCG(21). HTG(21). 4 UA(9), U(9). A(9)  COMMON /AREA1/ CN. HM, 00. SU. NI. ASH, H20. HFO. LAMBDA. MF, TS03 COMMON /AREA3/ HSOL, TSO, MSOL. MLIME • Set the S o l i d s Cooler O u t l e t Temperature' TSO - 200.0 C C COMMON /AREA 1/: COMBUSTION COMMON DATA C COMMON /AREA2/: HEAT TRANSFER COMMON DATA C LL • 1 CALL STEAM(MU. MU. MU, MU, MU, MU, MU, LL) C HG(8) • -1232.0 HG(10) • -1294.0 MG(8) • 1.0887 MST - 1.0 TG(17) - 340.0 TPR • 0.0 DO 10 IH • 1, 15 TS(IH) - 0.00 PS(IH) • 0.0 HS(IH) • 0.0 SS(IH) • 0.0 XS(IH) • 0.0 CPS(IH) - 0.0 HTS(IH) • 0.0 10 CONTINUE XS(14) " 1.0 DO 20 IH • 1, 21 TG(IH) • 0.00 PG(IH) • 0.0 HG(IH) • 0.0 SG(IH) • 0.0 MG(IH) - 0.0 CPG(IH) - 0.0 20 CONTINUE Read In the Coal A n a l y s i s READ (6,30) HFO, HCO, CN, HM. 00, SU, NI , ASH, H20 30 FORMAT (2F12.2, 7F1S.9) Read In the Operating Parameters READ (6.40) NX. COOLEF, TCOOL, PREF 40 FORMAT (14, 3F12.6) DO 90 IDF • 1 , NX READ (6,50) TAMB. PAMB, TMIN. TBED. TSTACK, PTURB, TTUR, LAMBDA. 1 TMAX. PMAX, PINTER, PARAM, NGC. NGT, NT  61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 lOO lot 102 103 104 105 106 107 108 109 110 111 112 113 114 115 116 117 11B 119 120  50  FORMAT (15F20.10)  Set the J s e n t r o p l c E f f i c i e n c i e s o f the Compressor, Gas and Steam T u r b i n e s , and the Feed Water Pump NGC - 0.86D0 NGT - 0.75 • 0.178 • PTURB - 0.048 • PTURB * PTURB IF (PTURB GE. 1.0) NGT • 0.88 NT > 0.895D0 NP • 0.8100 PGIC1 • 0.05 PGIC2 - 0.0O1 PGEC • 0.003 C a l c u l a t e the L.P. Compressor I n l e t P r o p e r t i e s PG(1) " PAMB • 0.995 TG(1) • TAMB MGO) - 1.0 CALL AIR(PG(1), TG(1), HQ(1), SG(1), MQ(1), CPG(1). HTG(1!, 1 PCG(1)) C a l c u l a t e the I n t e r c o o l e r I n l e t P r o p e r t i e s PG(2) - (PTURB«»0.57) • (PAMB*«0.43) MG(2) • 1.0 SG(2) • SG(1) CALL AIRS(PG(2). TG(2). HG(2). SG(2). MG(2). CPQ(2), HTG(2), 1 PCG(2)> HG(2) - HGO) • (HG(2) - HG(D) / NGC CALL AIRH(PG(2). TG(2), HG(2). SG(2). MG(2), CPG(2), HTG(2), 1 PCG(2)) C a l c u l a t e the I n t e r c o o l e r O u t l e t P r o p e r t i e s 00 60 I - 1, 3 PG(3) - PG(2) - PGIC1 MGO) • 1.0 TG(3) • TG(2) - COOLEF • (TG(2) - TMIN) CALL A I R ( P G O ) , TG(3). HG(3), SG(3). MG(3), CPQ(3), HTG(3), 1 PCG(3)) HINT • HG(2) - H G O ) PG(4) - P G O ) MG(4) " 1 . 0 TG(4) • TG(3) CALL AIR(PG(4), TG(4), HG(4), SG(4), MGO). CPG(4). HTG(4), 1 PCQ(4)) C a l c u l a t e the H.P. Compressor O u t l e t P r o p e r t i e s PG(5) " PTURB MGO) - 1.0 SGI 5) > SGI 4) CALL AIRS(PGO). TG(5). HG(9), SG(5). MQ(5), CPG(5). HTG(5), 1 PCG(5)) HG(5) - HG(4) • (HG(5) - HG(4)) / NGC CALL AIRH(PG(5). TG(5). HG(5), SG(5). MG(5), CPG(5), HTG(5). 1 PCG(5)) C a l c u l a t e the F l u l d l t z e d Bed I n l e t P r o p e r t i e s PG(7) - PG(5) MG(7) • MG(5) HG(7) • HG(5) + MG(8) / MG(5) • (HG(8) - HG(10)) CALL AIRH(PG(7), TG(7). HG(7), SG(7). MG(7), CPG(7), HTG(7), 1 PCG(7)) C a l c u l a t e Combustion and the PFB O u t l e t P r o p e r t i e s TG(8) - TBED PG(8) • PG(7) - 0.045 L2 - 0 CALL BED(HG(7) , MG(7), PGIB). TG(8). HG(8). SG(8). MG(8). 1  121 122 123 124 125 12fi 127 128 129 130 '.31 132 133 134 135 136 137 136 139 140 141 142 143 144 145 146 147 148 149 150 151 152 153 154 155 156 157 158 159 160 161 162 163 164 165 166 167 168 169 170 171 172 173 174 175 176 177 178 179 180  1 Calculate  HPFB, CPG(B), HTG(8), PCG(8), L2) the H.P.Turbine I n l e t P r o p e r t i e s TG( 10) - TTUH PG(10) - PG(8) - 0.045 * PTUR8 - 0.0014 MG(10) • MG(8) CALL GAS(PGdO). TGI 10), HG(10). SGI 10). MGI10), CPG(IO). 1 HTG(10). PCG(10)) C a l c u l a t e the L , P . T u r b ina I n l e t P r o p e r t i e s WC0MP2 - MC.(5) * IHGI5) - HG(4)) HGI15) * HG( 10) - WC0MP2 / MG(IO) / NGT SGf 1 5 ) - SGI 10) MGI 15) " MGI 10) CALL GAHSIPG(IS). TGI 1 5 ) , H G ( I 5 ) . SG(15). MG(15), CPG(IS), 1 HTG<15). P C G l 1 5 ) 1 HGI15) * HGI10) - WC0MP2 / MGI10) CALL GASH(P<-,( 15) . TGI 15). HGI15). SG(15), MG(15), CPG(15). 1 HTGI15), PCGl15)) C a l c u l a t e the Power Turbine I n l e t P r o p e r t i e s WCQMP1 • MGI1) * (HGI2) - HGIt)) HGI16) - H G I 1 5 ) - WC0MP1 / MGI15) / NGT SG|16) - SG(15) MGI16) • MGI15) CALL GAHSIPGI16). TG(16), HG(16), SGI 16). MG(16), CPG(16), 1 HTGI16). PCGI161) HG(16) • HGI15) - WCQMP1 / MG(15) CALL GASH!PG(16), TG(16). HG(16). SGI 16). MG(16). CPG(16), 1 HTGI16). PCG(16)) C a l c u l a t e the Power T u r b i n e O u t l e t P r o p e r t i e s MGI17) • MGI10) PG(17) " PAMB * PGEC SGI 17) - SGI 16) CALL GASSIPGI 17)'. TGI17), HG(17), SG(17). MG(17). CPGI17). 1 HTG(17), PCGl17)) HG(17) - HGI16) - NGT * (HGI16) - HGI17)) CALL GASH(PG(17). TGI 17). HG(17). SGI17), MGI17). CPG(17), 1 HTG(17). PCGI17)) C a l c u l a t e the Stack I n l e t P r o p e r t i e s TG(21) - TSTACK PGI21) - PAMB MGI 21) • MGI17) CALL GASIPGI21). TGI21). HG(21). SGI21), MGI21). CPGI21), 1 HTGI21), PCG(21)) C a l c u l a t e P r e s s u r e Drops and Economiser Heat T r a n s f e r HTE - (HGI17) - HGI21)) * MG(17) PGIC1 - 0.0003 • PGI2) « (HG(2) - HG(3)) PGIC2 " 0.0003 • PG(3) * (HG(3) - HG(4)) PGEC - 0.00033 • PGI17) • (HG(17) - HGI21)) TSTACK - TS03 + 10.0 60 CONTINUE C  STEAM PORTION OF PROGRAM PSOL • 0.069 PSEC • 0.67 PSSH • 1.2 PSRH - 0.2 MST - 0.5 C a l c u l a t e the H.P. Steam T u r b i n e I n l e t 70 PSI1) • PMAX TS(1) • TMAX LL » 2  Properties  181 182 183 184 185 186 187 i«8 189 190 19 1 192 193 194 195 196 197 198  199 200 201 202 203 204 205 206 207 208 209 210 211 212 213 214 215 216 217 218 219 220 221 222 223 224 225 226 227 228 229 230 231 232 233 234 235 236 237 238 239 240  CALL STEAM(PSO). T S ( 1 ) . HSI1). S S ( 1 ) . C P S O ) , HTS(1). PCS(1), LL) XS(1 ) • 1 .0 Calculate t h e Reheater Inlet Properties P S ( 3 ) • PINTER S5I3) » SSI 1) CALL S T A T 6 5 I P S ( 3 ) . T S I 3 ) . HSI3). S S ( 3 ) , CPSI3), XSI3). HTSI3). 1 PCSI.'))) H S ( 3 ) - M S I 1 ) - NT • (HSI1) - HSI3)) CALL S T A T E H I P S O ) . T S I 3 ) . HSI3). SSI3), CPSO). XSI3), HTSI3). 1 PCSI3)) C a l c u l a t e t h e L.P. S t e a m T u r b i n e I n l e t P r o p e r t i e s T S ( 4 ) - TMAX P S ( 4 ) « PSI3) - PSRH < S ( 4 ) - 1.0 LL • 2 C A L L STEAM!PSI 4) , T S I 4 ) . HS(4), S S ( 4 ) . CPS(4). HTSI4) , PCS(4). 1 LL) Calculate the Condenser Inlet Properties CALL P S A T l P L O W , TMIN) PSI5) - PLOW , • SSI5) • SSI4) CALL STATES!PSI5), T S I 5 ) , HS(5). S S ( 5 ) , C P S O ) , XSI5). HTSI5), 1 PCSI5)) HSI5) - HSI4) - NT • (HS(4) - HSI5)) CALL S T A T E H ( P S O ) , T S ( 5 ) , HS(5). S S ( 5 ) . C P S O ) . XS(5). HTSI 5 ) . 1 PCSI5)) CPS!5) - 0.0 C a l c u l a t e the Feed Water Pump I n l e t P r o p e r t i e s PSI6) - PLOW TSI6) • TMIN LL • 3 CALL STEAM(PS(6), T S ( 6 ) , HSI6), SSI6). CPS(6). HTSI6). PCSI6), 1 LL) C a l c u l a t e the Feed Water Pump O u t l e t P r o p e r t i e s PS(7) • PMAX + PSOL + PSEC • PSSH SS<7) - SSI6) CALL L I 0 S ( P S ( 7 ) , T S ( 7 ) . HS(7). S S ( 7 ) , CPS(7). XS(7), HTS<7), 1 PCS(7)( HSI7) - HSI6) + (HS(7) - HS(6)) / NP CALL L I 0 H ( P S ( 7 ) . T S I 7 ) . HSI7). S S I 7 ) . CPS!7). XS(7). HTSI7). 1 PCS!7)) C a l c u l a t e t h e P r o p e r t i e s a f t e r t h e I n t e r c o o l e r and S o l i d s C o o l e r PS(8) - PMAX • PSEC • PSSH HS(B) • HSI7) + (HINT + HSOL) / MST CALL L I Q H ( P S O ) . T S I 8 ) . HSI8), S S ( 8 ) . CPS(B). XS(8). HTS(8). 1 PCS(B)) C a l c u l a t e t h e Economiser O u t l e t p r o p e r t i e s HS(9) « HS(8) • HTE / MST PS(9) • PMAX + PSSH CALL S T A T E H ( P S O ) . T S ( 9 ) . HS(9). S S ( 9 ) , C P S O ) , X S O ) . H T S O ) . 1 PCS(9>) C a l c u l a t e the P r o p e r t i e s at the Onset of B o i l i n g PSI14) - PMAX • PSSH CALL TSAT(PS(14). T S ( 1 4 ) ) LL - 2 CALL STEAM(PS(14). T S ( 1 4 ) , HSI14), SS(14). CPS(14). HTSI14). 1 PCSI14), L L ) R e - E s t i m a t e t h e P r e s s u r e Drops and Steam Mass Flow HSTE - H S I D - HS(9) + HS(4) - HS(3) 1  241 IF (DABSfHPFB - MST'HSTE) .LE. 0.1) GO TO 80 242 MST - HPFB / HSTE 243 PSOL • HTS(7) • 0.000001 • (HS(8) - HSC7)) 244 PSEC • HTS(8) » 0.000001 • (HS(9) - HS(8)) 245 PSSH - HTS(14) • 0.000010 • (HS(1) - HS(14)) 24S PSRH • H T S O ) * 0.000028 • (HS(4) - HS(3)) 247 GO TO 70 24B 249 C a l c u l a t e t h e C y c l e Performance 250 SQ HEAT • MF * HCO 251 WGT • MG(16) * (HG(16) - HG(17)) 252 WST - MST • (HS(1) - HS(3) • HS(4) - HS<5)) 253 WP • MST • (HS(7) - HS(6)) 254 WORK • WGT + WST - WP 255 EFF - WORK / HEAT • 100 256 WR • WGT / WORK • 100 257 258 90 CONTINUE 259 STOP 260 END End o f f i l e  O  i  A1r Heater Cycle  s  Design Load Analysis  2  5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60  IMPLICIT REAL*8(A C  REAL'S 1 2 3 4  - H.O - Z)  TG(21). PG(21), HG(21), SG<21). MG(21), CPG(2t). LMT3. NGT. NGC, NP, NT, NI, MF, MST 1, MST, LAMBDA, MU, KT, MSOL, MLIME, INC. PS(15), TS(15), HS(15), SS(15), XS(15). C P S O S ) , FAG(21), FAS(15). HTS(15). PCS(15). PCG(21). HTG(21), UA(9). U ( 9 ) . A(9)  C  COMMON /AREA 1/ CN, HM. 00. SU, NI, ASH, H20. HFO. LAMBDA, MF, TS03 COMMON /AREAS/ HSOL, TSO. MSOL, MLIME Set the S o l i d s CooIor O u t l e t Temperature TSO • 200.0 C C COMMON /AREA 1/: COMBUSTION COMMON DATA C COMMON /AREA2/: HEAT TRANSFER COMMON DATA C LL - 1 CALL STEAMfMU, MU. MU. MU. MU, MU. MU, L L ) C HG(8) • -1232.0 HG(10) • -1294.0 MG(8) - 1.0887 MST - 1.0 TG(17) » 340.0 TPR - 0.0 DO 10 IH • 1, 15 TS(IH) - 0.00 PS(IH) • 0.0 HS(IH) • 0.0 SSIIH) - 0.0 XS(IH) - 0.0 CPS(IH) • 0.0 HTSCIH) - 0.0 10 CONTINUE. XS(14) - 1.0 DO 20 IN 1 , 6 TG(IH) - 0.00 PG(IH) - 0.0 HG(IH) • 0.0 SG(IH) • 0.0 MG(IH) - 0.0 CPG(IH) • 0.0 20 CONTINUE 1  Read  In the Coal A n a l y s i s READ (6.30) HFO, HCO, CN, HM, 00, SU. NI, ASH. H20 30 FORMAT (2F12.2. 7F15.9)  Read  1n the O p e r a t i n g Pasrameters READ (6,40) NX, X6, PREF 40 FORMAT (14. 2F12.6) DO 260 IOF - 1 , NX READ (6.50) TAMB, PAMB. TMIN, TBED. TSTACK, PTURB. TTUR. LAMBDA 50 FORMAT (12F2O.10)  61 62 63 64 65 66 67 68 69 70  Set t h e I s e n t r o p i c E f f i c i e n c i e s NP " 0.8100 NGC - 0.926 - 0.0046 » PTURB / PAMB NGT • 0.88 PGEC - 0.001 C a l c u l a t e the Compressor I n l e t P r o p e r t i e s PG(1) • PAMB • 0.995 TG(1) - TAMB MG(1) • 1.0 CALL AIR(PG(1). TG(1), HQ(1), SG(1), MG(1), CPG(1), HTG( 1).  71  72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 107 108 109 110 111 112 1 13 114 115 116 117 118 119 120  1  .  PCG(D)  C a l c u l a t e the Compressor O u t l e t P r o p e r t i e s PG(5) • PTURB MG(5) • 1.0 SG(5) - SG(1) CALL AIRS(PG(5>, TG(5), HG(5), SG(5). MG(5), CPG(5), HTG(5), 1 PCGO)) HG(5) - H G O ) + (HG(5) - HG(1)) / NGC CALL AIRH(PG(5), T G ( 5 ) . HG(5), SG(S), MG(8). CPQ(5). HTG(5), 1 PCG(5)) C a l c u l a t e the Bed I n l e t P r o p e r t i e s PG(7) - PG(5) TG(7) • TG(5) HG(7) - HG(5) SG(7) • SG(5) MG(7) • MG(5) CPG(7) • CPG(5) MGOO) " 2 . 0 ' -* IK - 0 cn C a l c u l a t e Combustion and Bed O u t l e t P r o p e r t i e s —• 60 TG(8) • TBED PG(8) - PG(7) - 0.045 LZ • O CALL BED(HG(7), MG(7). PG(8). TG(8), HG(8), SG(8). MG(8). HPFB, 1 CPG(B). HTG(8), PCG(8). LZ) C a l c u l a t e the P r o p e r t i e s a f t e r Hot Gas F i l t r a t i o n TG(9) • TG(8) PG(9) - PG(8) - 0.045 • PTURB - 0.0014 MGO) • MG(B) HGO) " HGO) \ SG(9) • SG(8) C P G O ) " CPG(8) C a l c u l a t e the C o o l a n t A1r I n l e t P r o p e r t i e s PG(10) • PG(5) T G O O ) - TG(5) HG(10) - HG(5) SG(10) • SG(5) CPG(10) - CPG(5) C a l c u l a t e the C o o l a n t A1r O u t l e t P r o p e r t i e s PG<12) • PG(9) HG(12) - HGOO) + HPFB / MGOO) MG(12) ' MG(10) CALL AIRH(PG(12), TG(12), HG(12). SG(12). MG(12), CPG(12). 1 HTG(12), PCG(12)) C a l c u l a t e P r o p e r t i e s o f the Combustion Gas and Coolant A1r Mixture PG(13) - PG(9) CALL MIX(PG(13), TG(13). HG(13), HG(12). H G O ) , SG(13), MG(13). 1 MG(12), M G O ) , CPG( 13) , HTG(13). PCG( 13)) Check the T u r b i n e I n l e t Temperature, and If wrong. Change the Coolant Flow. A Newton - Raphson Convergence Technique 1s used.  121 122 123 124 125 126 127 128 129 130 131 132 133 134 135 . 136 137 138 139 140 141 142 143 144 145 146 147 148 149 150 151 152 153 154 155 156 157 158 159 160 161 162 163 164 165 166 167 168 169 170 171 172 173 174 175 176 177 178 179 180  IF (DABS(TG(13) - TTUR) .LE. 0.1) GO TO 90 ERR « TG(13) - TTUR IF (IK .GE. 1) GO TO BO C  E l • ERR FI - MG(10) IK • 1 MGI 10)"MG(10)-0.5 GO TO 60  C 80  E2 - ERR F2 - MG(10) MG(10) • (F1»E2 - F2«E1) / (E2 - E l ) E l • E2 F1 • F2 GO TO 60 1  C  90 MGI1) • MGI10) + 1.0 MGI5) • MG( 1) C a l c u l a t e t h e H.P.Turbine O u t l e t P r o p e r t i e s WCOMP • MG(1) • (HG(7) - HG(1)) HG(15) » HG(13) - WCOMP / MG(13) / NGT SGI 15) • SGI 13) MGI15) • MGI13) CALL GAHS(PG(15). TG(15), HG(15). SG(15). MG(15). CPG(15), 1 HTGI15). PCGl15)) HGI15) • HGI 13) - WCOMP / MG(13) CALL GASH(PG(15), TG(15). HG(1S), SGI 15). MG(15). CPG(15). 1 HTG(15), PCGI15)) C a l c u l a t e t h e Power T u r b i n e O u t l e t P r o p e r t i e s 100 MGI18) • MGI13) PG(18) • PAMB + PGEC SG(18) • SGI 15) CALL GASSIPGI18), TG(18), HGI18). SG(18), MG(18), CPGI18). 1 HTGI18), PCGl181) HG(18) - HG(15) - NGT • (HGI15) - HGI18)) CALL GASH(PG(18). TG(18). HGI18). SGI 18), MG(18). CPGI18). 1 HTGI18), PCG(18)) C a l c u l a t e t h e P r o p e r t i e s a t the Stack I n l e t 110 TG(21) - TSTACK PG(21) • PAMB MGI21) • MG(18) CALL GASIPGI21), TGI21). HG(21), SGI21). MG(21), CPGI21), 1 HTG(21), PCGl21)) PGEC - 0.00004 • PG(18) • (HG(18) - HGI21)) IF (DABS(PG(18) - PAMB - PGEC) .GT. 0.0001) GO TO 100 TSTACK • TS03 + 10.0 IF (0ABSITGI21) - TSTACK) . GE . 0.5) GO TO 110 TS03A - TS03 HTE - MGI21) • (HG(18) - H G I 2 D ) + HSOL C C STEAM PORTION OF PROGRAM C C a l c u l a t e t h e Condenser O u t l e t P r o p e r t i e s IF - O CALL PSAT(PS(1), TMIN) LL - 3 TS(1) " TMIN CALL STEAM(PS(1), T S ( 1 ) . HS(1), SS(1). CPS(1). HTS(1). PCS(1), 1 LL)  181 182 183 184 185 186 187 188 189 190 191 192 193 194 195 196 197 198 199 200 201 202 203 204 205 206 207 20B 209 210 211 212 213 214 215 216 217 218 219 220 221 222 223 224 225 226 227 228 229 230 231 232 233 234 235 236 237 238 239 240  E s t i m a t e t h e S a t u r a t e d Steam Temperature and P r e s s u r e TS(5) - TS(1) + 0.80 • (TG(18) - T S ( D ) PS(5) - DEXPK-2.9531 + ,0137682*TSO) - 0.07726* ( ( TS( 5)/100.0) * 1 *2))) NT - 0.8035 + 0.0001 * T S ( 5 ) C 120 CALL STATET(PS(5). T S ( 5 ) . HS(5). S S ( 5 ) . CPS(5), XS(5), HTS(5). 1 PCS(5)) C a l c u l a t e t h e Steam T u r b i n e O u t l e t P r o p e r t i e s PS(6) • P S ( 1 ) SS(6) • SS(5) CPS(6) - 0.0 CALL STATES(PS(6), T S ( 6 ) , HS(6), SS(5), CPS(6), XS(6). HTS(6), 1 PCSI61) HS(6) - HS(5) - NT * (HS(5) - HS(6)) CALL STATEH(PS(6). T S ( 6 ) . HS(6). S S ( 6 ) . CPS(6), XS(6), HTSI6). 1 PCS(6)) C a l c u l a t e t h e Feed Water Pump O u t l e t P r o p e r t i e s PS(2) • P S ( 5 ) SS(2) • S S ( 1 ) CALL L I 0 S ( P S ( 2 ) , T S O ) . HS(2). SS(1), CPS(2), XS(2), HTS(2), 1 PCSI2)) HS(2) - HS(1) + (HS(2) - H S ( D ) / NP CALL LI0HIPSI2), T S I 2 ) . HSI2), SSI2). CPSI2), XS(2). HTSI2), 1 PCSI2)) C a l c u l a t e t h e Steam Mass Flow MST " HTE / (HS(5) - HS(2)) C a l c u l a t e t h e P r o p e r t i e s a t t h e Onset o f B o i l i n g PSI3) - P S ( 5 ) CALL T S A T ( P S O ) . T S ( 3 ) ) LL - 3 CALL STEAM(PS(3), T S ( 3 ) , HS(3), SSI3), C P S O ) , H T S O ) , P C S O ) 1 LL) C a l c u l a t e t h e Gas P r o p e r t i e s C o r r e s p o n d i n g t o the Onset o f B o i l i n g HGI 20) - HGI21) * ( H S O ) - HS(2)) • MST / MGI 18) PG(20) • PAMB MG(20) - MGI18) CALL GASHIPGI20), TG(20). HGI20), SGI20), MG(20), CPG(20), 1 HTG(20), PCG(20)) C a l c u l a t e the Pinch Point Separation TPIN • TS(2) + 0.80 » (TG(20) - T S ( 2 ) ) TPIND • TPIN - T S O ) IF ( I F .GE. 1) GO TO 150 IF ( T S O ) .LT. TPIN) GO TO 160 IF - 1 140 TPI1 • TPIND , PI « P S O ) P S O ) - P S O ) + TPIND / 10.0 IF ( P S O ) LE. 0.0) P S O ) • - P S O ) / 10.0 GO TO 120 150 TPI2 • TPIND P2 - P S O ) IF (DABS(TPIND) .LE. 0.5) GO TO 160 P S O ) - (P2»TPI1 - P1»TPI2) / ( T P I 1 - TPI2) IF ( P S O ) .LE. O.O) P S O ) - - P S O ) / 10.0 TPI1 - TPI2 P1 - P2 GO TO 120 C a l c u l a t e t h e C y c l e Performance  241 242 243 244 245 246 247 248 249 250 251 End o f f i l e  160  HEAT * MF * HCO WGT « MG(1S) • (HGC15) - HG(18)) WST « MST • (HS(5) - HS(6)) WP - MST • (HS(2) - HS(1)) • 0.0015 • WST WORK • WGT • WST - WP EFF • WORK / HEAT • 100 WR » WGT / WORK • 100 260 CONTINUE STOP END  Air  1 2 3 4 5 7 8 9 10 1 1 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60  Heater Cycle  Design Load Analysis f o r Part Load Simulation IMPLICIT REAL*8(A - H,0 - Z)  C  C  c c c c c c c c c c c c c c  REAL*8 TG(21), PG(21), HG(21). SG(21). MG(21). CPG(21). NGT. NGC. I NP. NT, NI. MF. MST1, MST. LAM80A, MU. KT. IMT( 5), MRATE, 2 PS(6). T S ( 6 ) . HS(6). SS(6). XS(6). CPS(6). FAG(2I). FAS(6). 3 HTS(6). PCS(6). PCG(21). HTG(21). PDS(S). P0G(5), UA(5). 4 U(5), A(5) INTEGER OPT. TYPE TVPE - 0 OPT • 0 OPT: HEAT EXCHGER CALC INSTR. TVPE: HEAT TRANSFER CONDITIONS  1- KNOW HOT OUTLET TEMP 2- KNOW COLD OUTLET TEMP 1234-  INSIDE TUBE (TURBULENT) OUTSIDE TUBE (TURBULENT) OUTSIDE TUBE (BUBBLY PFB) BOILING HEAT TRANSFER IN TUBES (CALCULATED AT LIQUID END)  • CDMMON /AREA1/ CN. HM. 00, SU. NI. ASH. H20. HFO. LAMBDA. MF, TS03 COMMON /AREA2/ VEL, RHO. AREA, DIAM, MU. KT. PR. REV, EPS, TVPE COMMON /AREA1/: COMBUSTION COMMON DATA COMMON /AREA2/: HEAT TRANSFER COMMON DATA LL » 1 CALL STEAM(MU, MU, MU. MU. MU, MU. MU, L L )  UK • 1 MST - 1.0 PDS(1 ) - 0.0 PDS(2) - 0.0 DO IO IH • 1. 21 TG(IH) ' 0 . 0 0 PG(IH) • 0.0 HG(IH) • 0.0 SG(IH) - 0.0 MG(IH) • 0.0 CPG(IH) • 0.0 HTG(IH) - 0.0 PCG(IH) - 0.0 FAG(IH) • 0.0 10 CONTINUE Read In the Coal A n a l y s i s READ (6.20) HFO. HCO, CN. HM, 00, SU, NI, ASH, H20 20 FORMAT (2F12.2, 7F15.9) Read m the O p e r a t i n g Perameters READ (6,30) NX. X6, PREF 30 FORMAT (14, 2F20.10) READ (6.40) TAMB. PAMB. TMIN. TBED. TSTACK. PTURB. TTUR. LAMBDA 40 FORMAT (1OF20.10) OIAM - 0.10 Set t h e I s e n t r o p l c E f f i c i e n c i e s NGC - 0.894200  61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 107 108 109 110 111 112 113 114 115 116 117 118 1 19 120  NGT = 0.88D0 NT = O 8449D0 NP = 0.81D0 Set the Bed H e i g h t and P r e s s u r e Drop PFBHT - 4.9 PDBED - 0.045 C a l c u l a t e the Compressor I n l e t P r o p e r t i e s PG(1) - PAMB • .995 TG(1 ) - TAMB MG(1) • 2.930 VEL - 15.0 TVPE • O CALL AIR(PG(1). TG(1). HG(1). SG(1). MG(1), CPG(1). HTG(1). 1 PCG(1)) C a l c u l a t e the Compressor O u t l e t P r o p e r t i e s PG(5) =• 0.70000 MG(5) = MG(1) SG(5) • SG(1) CALL AIRS(PG(5). TG(5). HG(5). SG(5). MG(5). CPG(S). HTG(5), 1 PCG(5)) HG(5) - H G O ) • (HG(5) - H G O ) ) / NGC OIAM • O.10 TYPE • O VEL . 1 . 4 I CALL AIRH(PG(5), TG(5), HG(5). SG(5). MG(5). CPG(5). HTG(5), 1 PCG(5)) FAG(5) - MG(5) / RHO / VEL FAGOO) • 2.167 / RHO / VEL FAG(7) - 1.0 / RHO / VEL C a l c u l a t e the F l u i d i z e d Bed I n l e t P r o p e r t i e s PG(7) - PG(5) TG(7) - TG(5) HG(7) • HG(5) SG(7) - SG(5) MG(7) • 1.0 CPG(7) • CPG(5) HTG(7) • HTG(5) PCG(7) " PCG(5) ' C a l c u l a t e Combustion and the F l u i d i z e d Bed O u t l e t P r o p e r t i e s TG(8) » 900.0 PG(8) - 0.65500 LZ « 0 TYPE " 3 VEL - 0.82 CALL BED(HG(7) , MG(7). PG(8), TG(B), HG(8), SG(B), MG(8). HPFB. 1 CPG(8). HTG(8), PCG(8), L Z ) FAG(8) - MG(8) / RHO / VEL PDBED = 0.00980 * PFBHT • (1 - EPS) C a l c u l a t e the Gas P r o p e r t i e s a f t e r the Hot Gas Cleanup TG(9) - TG(8) PG(9) - O.6221D0 MGO) • MGO) TYPE * O CALL G A S ( P G O ) , T G O ) . H G O ) . S G O ) , M G O ) , C P G O ) , H T G O ) , 1 PCGO)) F A G O ) • M G O ) / RHO / VEL C a l c u l a t e the C o o l i n g A i r I n l e t P r o p e r t i e s PG(10) " PG(5) TG( 10) • TG(5)i MG(10) . 1.93000  (j!  I  121 122 123 124 125 126 127 128 129 130 131 132 133 134 135 136 137 138 139 140 141 142 143 144 145 146 147 148 149 150 151 152 153 154 155 156 157 158 159 160 161 162 163 164 165 166 167 168 169 170 171 172 173 174 175 176 177 178 179 180  TYPE » 1 VEL " 1.4 CALL AIR(PGOO), TG(10), HG(10), SGI 10). MGI10). CPGI10). HTGI10), 1 PCGl 10)) FAGI10) - MGI10) / RHO / VEL C a l c u l a t e the C o o l i n g A i r O u t l e t P r o p e r t i e s PG(12) • PGI9) HGI12) " HGI10) + HPFB / MGI10) MGI12) - MG(10) TYPE • 1 VEL - 1.4 CALL AIRHIPGI12), TGI12), HGI12), SGI12), MG(12), CPGI12). 1 HTGI12). PCGl12)) FAG(12) - MGI12) / RHO / VEL C a l c u l a t e t h e C o o l i n g A1r and Combustion Gas M i x t u r e P r o p e r t i e s PG(13) • PG(9) TYPE - 0 CALL MIXIPGI13), TGI13), HGI13). HGI12), HGI9), SGI 13), MGI13), 1 MG(12), MG(9), CPG(13), HTGI13), PCGl13)) C a l c u l a t e t h e H.P.Turbine O u t l e t P r o p e r t i e s WCOMP • MG(1) • (HGI7) - HGIt)) HGI15) • HGI13) - WCOMP / MGI13) / NGT SGI 15) • SG(13) MGIIS) ' MGI13) CALL GAHSIPGI15), TGI15), HG(15), SGI15), MGI15), CPG(15). 1 HTGI15). PCGl151) HGI15) " HGI13) - WCOMP / MGI13) CALL GASHlPGI15), TG(15). HGI15). SGI 15), MGI15), CPGI15). 1 HTGI15), PCGl15)) C a l c u l a t e the L P . T u r b i n e O u t l e t P r o p e r t i e s 50 MGI18) • MGI13) PG(18) - O.102900 SGI 18) « SGI 15) CALL GASSIPGI18), TGI18). HGI18). SGI 18). MGI18). CPG(18). 1 HTGI18), PCGl18)) HG(18) " HG(15) - NGT • (HGI15) - HG(18)) TYPE - 2 VEL - 15.0 DI AM - 0.05 CALL GASHlPGI18), TGI 18). HGI18). SGI18). MG(18). CPGI18), 1 HTGI18), PCGl18)) C a l c u l a t e the Stack I n l e t Gas P r o p e r t i e s TG(21) - 157.11 PGI21) • PAMB MGI21) • MGI18) CALL GAS(PG(21), TGI21), HGI21). SGI21). MGI21). CPGI21), HTGI21). 1 PCGI21)) FAG(21) - MG(21) / RHO / VEL Determine the Heat T r a n s f e r Area f o r the PFB CIC - (HG(12) - HG(10)) / ITG(12) - TGI 10)) • MG(10) CIH - 100000.0 OPT • 2 CALL HTXCHGt TG(8). TG(8), C1H, TGI 10), TGI12). C1C, UA(1), OPT) C C STEAM PORTION OF PROGRAM C MST • 0.3737 TYPE " 0 C a l c u l a t e the Condenser O u t l e t P r o p e r t i e s TS(1) - TMIN  181 182 183 184 185 186 187 188 189 190 191 192 193 194 195 196 197 198 199 200 201 202 203 204 205 206 207 208 209 210 211 212 213 214 215 216 217 218 219 220 221 222 223 224 225 226 227 228 229 230 231 232 233 234 235 236 237 238 239 240  CALL P S A T I P S I D , T S ( O ) LL - 3 CALL STEAMIPS(I), TS<1). HS<1). SSI 1 ) . C P S O ) . HTSI 1 ), P C S I D , LL) XSl 1 ) • 0.0 C a l c u l a t e the Feed Water Pump O u t l e t P r o p e r t i e s VEL - 0.4 TYPE • 1 PSI2) - 1.5657 S S O ) - SSI 1) CALL L I 0 S ( P S ( 2 ) . T S ( 2 ) . H S U ) . SS(2). CPS(2). XS(2). HTS(2). 1 PCS(2)) HS(2) - HS(1) + (HS(2) - H S ( O ) / NP CALL LI0HIPSI2). T S ( 2 ) . H S U ) . SS(2), CPS(2). XS(2), HTS(2), 1 PCS(2)) FAS(2) - MST / RHO / VEL C a l c u l a t e t h e Steam P r o p e r t i e s a t t h e Onset o f B o i l i n g P S O ) •= P S O ) CALL T S A T I P S O ) . T S O ) ) LL • 3 VEL - 0.4 TYPE • 4 CALL STEAM(PSO), T S O ) . H S O ) . S S ( 3 ) . C P S O ) , H T S O ) , P C S O ) , LL) F A S O ) - MST / RHO / VEL XS(3) - 0.0 C a l c u l a t e the S u p e r h e a t e r I n l e t Steam P r o p e r t i e s PS(4) - P S O ) —* TS(4) • T S O ) Ol VEL - 10.0 CJ1 TYPE • 1 LL - 2 , CALL STEAM(PS(4). T S ( 4 ) . HS(4), S S ( 4 ) . CPS(4), HTSI4), PCS!4), L L ) FASI4) - MST / RHO / VEL XS(4) - 1.0 C a l c u l a t e t h e S u p e r h e a t e r O u t l e t Steam P r o p e r t i e s PSO) - PSO) T S O ) • 414.04D0 LL - 2 CALL STEAM(PSO). T S O ) . H S O ) , S S O ) . C P S O ) . H T S O ) . P C S O ) . LL) F A S O ) - MST / RHO / VEL X S O ) " 1.0 C a l c u l a t e t h e Steam T u r b i n e O u t l e t P r o p e r t i e s P S O ) - PS( 1) SSO) - SSO) 60 CALL S T A T E S ( P S O ) . T S O ) . HS<6). S S O ) . C P S O ) . X S O ) . H T S O ) , 1 PCSO)) H S O ) - H S O ) - NT • ( H S O ) - H S O ) ) CALL S T A T E H ( P S O ) , T S O ) . H S O ) . S S O ) . C P S O ) . X S O ) . H T S O ) , 1 PCSO)) C a l c u l a t e t h e Steam Mass Flow MST - (HG(18) - HG(21 ) ) / ( H S O ) - HS(2)) • MG(18) C a l c u l a t e t h e S u p e r h e a t e r O u t l e t Gas P r o p e r t i e s HGI 19) - HGI 18) - ( H S O ) - HS(4)) • MST / MG( 18) PGI19) - PAMB MGI19) • MGI18) VEL « 15.0 TYPE - 2 CALL GASHlPGI19). TG(19), HG(19), SG(19), MGI19). CPG(19). 1 HTG(19). P C G l 1 9 ) ) FAGI19) • MG(19) / RHO / VEL C a l c u l a t e the Gas P r o p e r t i e s C o r r e s p o n d i n g t o the Onset of B o i l i n g  24 1 242 243 244 245 246 247 248 249 250 251 252 253 254 255 256 257 258 259 260 261 262 263 264 265 266 267 268 269 270 271 272 273 274 275 276 277 278 279 280 281 282 283 284 285 286 287 288 289 290 291 292 293 294 295 296 297 298 299 300  HG(20) - HG(19) - (HS14) - HS<3)> • MST / MG(18) PG120) - PAMB MGI20) • MGI18) TYPE - 2 VEL = 15.0 CALL GASH(PG(20), TGI20), HGI20), SGI 20), MGI20). CPGI20), 1 HTGI20). PCGI20)) FAGI20) - MGI20) / RHO / VEL C a l c u l a t e t h e Heat T r a n s f e r Areas f o r the Three S e c t i o n s o f t h e HRSG CSC » (HSI5) - HSI4)) / (TSI5) - TS(4)) • MST C4C « 100000.0 C5C • ( H S O ) - HS(2)) / ( T S O ) - TS(2)) • MST C3H - (HGI18) - HG(19)) / (TG(18) - TGI 19)) • MGI18) C4H » (HG(19) - HG(20)) / (TGI 19) - TG(20)) » MG(18) C5H • (HGI21) - HG( 20)) / ( T G O I ) - TG(20)) • MGOB) OPT « 2 CALL HTXCHG(TG( 18), TG(19), C3H, T S O ) , T S O ) , CSC, UA(3), OPT) OPT - 1 CALL HTXCHGlTGI 19), TG(20), C4H. T S O ) . T S O ) , C4C, UA(4), OPT) OPT • 1 CALL HTXCHG(TG(20). TG(21), C5H, T S O ) . T S O ) . C5C. U A O ) .OPT) C U(1) - 1.0 / <2.0/(HTG( 10) • HTG( 12)) + 1.0/HTGO)) U O ) - 1.0 / (2.0/(HTG( 18) + HTG( 19)) + 2.0/(HTS(4) + H T S O ) ) ) U(4) - 1.0 / (2.0/(HTG( 19) + HTGI 20)) + 1.0/HTSO)) U O ) • 1.0 / (2.0/(HTG(20) + H T G O O ) + 1.0/HTSO)) C DO 70 I • 1. 5 IF (I .EQ- 2) GO TO 70 A(I) • UAO) / U O ) 70 CONTINUE FAS(1) • 0.0 HTS(1) - 0.0 C a l c u l a t e t h e C y c l e Performance HEAT - MF • HCO WGT « MGI15) • (HG(15) - HGI18)) WST • MST • ( H S O ) - H S O ) ) WP - MST • ( H S O ) - H S O ) ) + 0.0015 • WST WORK " WGT + WST - WP EFF • WORK / HEAT • 100 WR - WGT / WORK • 100 v  C C C  C  c  DATA FOR OFF-LOAD PROGRAM DO 210 I - 1. 21 WRITE (7.200) PG(I), 200 FORMAT (6F15.7) 210 CONTINUE  T G ( I ) , HG(I). M G O ) . FAG( I ) , HTG( I )  F A S O ) • 0.0 H T S O ) - 0.0 00 230 1 - 1 . 6 WRITE (7.220) P S ( I ) . T S O ) . H S O ) . F A S O ) . HTS(I) 220 FORMAT (5F15.7) 230 CONTINUE A O ) = 0.0 DO 250 I - 1, 5  301 WRITE (7,240) A l l ) 302 240 FORMAT (F15.7) 303 250 CONTINUE 304 C 305 MRATE " MG(7) / MG(1) 306 WRITE (7.260) MST, MRATE. MF, EPS, NGC, NGT. NT. NP. PDBED 307 260 FORMAT (9F15.7) 308 C 309 STOP 310 END End of f i l e  A i r Heater Cycle  i  2  Part Load Analysis  3  4 5 6 7 8 9 10 11 12 13 14 15 1G 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60  C  C  IMPLICIT REAL"8(A - H.O - Z) REAL*8 1 2 3 4 5 6  TG(21), PG(21), HG(21). SG(21). MG(21), CPG(21), NGT. NGC, NT. NI, MF. MST1, MST, LAMBDA, MU. KT. LMT(5), VG<5). V S ( 5 ) . PS(6). T S ( 6 ) . HS(6). SS(6). XS(6). CPS(6). FAG(21). FAS(S), HTS(6). PCS(6). PCG(21). HTG(21), PDS(S), PDG(5), UA(5), U ( 5 ) . A ( S ) . MRATE. MD1. MD2. MD3. ND1. ND2. ND3. MASS 1. MASS2. MASS3. MG13. MG15. NGT2, NGT3, MS2, MASS. NP INC, MSS. MS4. MSS, MGB  INTEGER OPT, TYPE TYPE • 0 OPT " 0 COMMON /AREA1/ CN, HM. 00. SU. NI. ASH. H20. HFO. LAMBDA, MF. TSO COMMON /AREA2/ VEL, RHO. AREA. DIAM, MU, KT, PR, REY, EPS. TYPE  Read I n D e s i g n Load Data DO 20 I - 1. 21 READ (7.10) PG(I), T G ( I ) . HG(I), MG(I), FAG(I), HTG(I) 10 FORMAT (SF15.7) 20 CONTINUE DO 40 I • 1, 6 READ (7.30) P S ( I ) . T S ( I ) . H S ( I ) . FAS(I). HTS(I) 30 FORMAT (5F15.7) 40 CONTINUE DO 60 I - 1, 5 READ (7,50) A ( I ) 50 FORMAT (F15.7) 60 CONTINUE READ (7,70) OMST, MRATE. OMF, EPS, EDI, ED2, NT. NP, PDBED 70 FORMAT (9F15.7) I n i t i a l i s e Steam Subroutines LL - 1 CALL STEAM(MU, MU. MU. MU. MU. MU. MU. LL) UK - 1 MST " OMST MF - OMF PAMB • PG(?1) TAMB • TG(1) C • DO 80 IH • 1, 21 SG(IH) • 0.0 CPG(IH) - 0.0 PCG(IH) - 0.0 80 CONTINUE PFBHT « 4.9 OEPS - EPS VOL - (1.0 - EPS) * PFBHT Read I n Coat A n a l y s i s READ (6,90) HFO, HCO. CN. HM, 00. SU. NI, ASH, H20 90 FORMAT (2F12.2, 7F15.9) Read I n the O p e r a t i n g Parameters READ (6.100) NX 100 FORMAT ( 14 )  61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 107 108 109 110 111 112 113 114 115 116 117 118 1 19 120  DO 360 IOF * 1. NX READ (6.110) LAMBDA. PFBHT, BYPASS, TEMP, TAMB 110 FORMAT (5F20.10) DIAM • O.10 Set the D e s i g n Flow V e l o c i t i e s VG(1) » 0.82 VG(2) - 0.82 VG(3) • 15.0 VG(4) - 15.0 VG(5) • 15.0 VS(1) " 1.4 VS(2) - 1.4 VS(3) • 10.0 VS(4) - 10.0 VS(5) - 0.4 C MG18 - MG(18) TMIN • TS(1) TBED - TG(8) TEMP - TG(8) FO - OMST • DS0RT(TS(5) + 273.15) / PS(5) C a l c u l a t e the Compressor D e s i g n Parameters R0T1 « 1.0 MD1 • MG(1) * DSQRT(TGO) + 273.15) / PG(1) ND1 • 1 / DSQRT(TGO) + 273.15) PD1 - PG(7) / PG(1) C a l c u l a t e the H.P.Turbine D e s i g n Parameters MD2 • MG(13) * 0S0RT(TG(13) * 273.15) / PG(13) ND2 - 1 / DSQRT(TG(13) + 273.15) P02 " PG(13) / PG(15) NGT2 - ED2 MASS2 - 1.0DO C a l c u l a t e the Power T u r b i n e D e s i g n Parameters R0T2 » 1.0 MD3 • MG(15) • DSQRT(TG(15) + 273.15) / PG(15) ND3 • 1 / DS0RT(TG(15) • 273.15) PDS • PG(15) / PG(18) EDS " ED2 C a l c u l a t e t h e Compressor I n l e t P r o p e r t i e s 120 VEL - 15.0 TG(1) - TAMB TYPE - O , CALL AIR(PG(1), TG(1), HG(1), SG(1), MG(1),. CPG(1), HTG(1), 1 PCGO)) Determine t h e Compressor C h a r a c t e r i s t i c s MASS 1 • M G O ) • DSORT(TGO) + 273.15D0) / PG(1) / MD 1 SPEE01 - R0T1 / DS0RT(TG(1) + 273.15) / ND1 MS2 = MASS2 * MD2 00 130 I • 1. 7 CALL GC(SPEED1, MASS 1, NGC, PR 1. P01. ED1, PSUR) MASS • MS2 / MD1 * PG(13) / PG(5) • DS0RT((TG(1) + 273.15)/( 1 TG( 13) + 273.15)) / MG(13) » MGO) • PR 1 MASS 1 « (MASS + 2.0*MASS1) / 3.0 IF (DABS(MASS - MASS 1) .LE. 0.00005) GO TO 140 130 CONTINUE 140 M G O ) =• MASS 1 / DSORT(TGO) + 273.15) • P G O ) • MD 1 C a l c u l a t e the Compressor O u t l e t P r o p e r t i e s PG(5) • PG(1) • PR 1 MG(5) * MG(1) SG(5) " S G O )  121 122 123 124 125 126 127 128 129 130 131 132 133 134 135 136 137 138 139 140 141 142 143 144 145 146 147 148 149 150 151 152 153 154 155 156 157 158 159 160 161 162 163 164 165 166 167 168 169 170 171 172 173 174 175 176 177 178 179 180  TYPE • O CALL AIRS(PG(5), TG(5), HG(5). SG(5), MGO), CPG(5), HTG15). 1 PCG(5)) HG(5) - HG(1) + (HG(5) - HG(1)) / NGC DIAM - 0.10 CALL AIRH(PG(5), TG(5), HG(5), SG(5), MG(5). CPG(5). HTG(5), 1 PCG(5)) S p l i t o f f the Bypass A i r MGB • MGI5) • BYPASS MG(5) - MG(5) - MGB C a l c u l a t e the F l u i d i z e d Bed I n l e t P r o p e r t i e s MGI7) » MGI5) • MRATE TG(7) - TG(5) HG(7) • HGI5) PG(7) • PGI5) SG(7) - SGI5) CPGI7) • CPGI5) HTGI 7 ) - HTGI 5 ) C a l c u l a t e Combustion and the F l u i d i z e d Bed O u t l e t P r o p e r t i e s 150 TG(8) • TEMP PG(8) • PGI7) - 0.0305 * ((VG(1)/0.82)*»2) - PDBED LZ - 1 TYPE • 3 VEL " V G I D CALL BEDIHGI7), MGI7), PGI8), TGI8), HG(8). SGI8). MGI8), HPFB, 1 CPGI8), HTGI8), PCG(B>; LZ) VGI1) • MG(8) / RHO / FAGl8) PDBED - 0.0098 • (1 - EPS) • PFBHT C a l c u l a t e the Heat T r a n s f e r t o the Coolant A i r C1C - (HGI12) - HGI10)) / (TG(12) - TG(10)) • MG(10) C IH • 100000.0 U(1) • 1.0 / (2.0/(HTG(10) t HTG(12)) + 1.0/HTGI8)) UAI1) - A H ) * U(1) OPT - 2 CALL EFFECT(TG(8) , TG(8), C IH, TG(10). TG(12). C1C, U A O ) , OPT) C a l c u l a t e Gas P r o p e r t i e s a f t e r the Hot Gas Cleanup TG(9) • TG(8) PG(9) • PG(8) - 0.0329 • ( ( V G O )/0.82 )••2 ) M G O ) - MGI8) TYPE - 0 CALL GAS(PGO), TG( 9) , H G O ) , SG(9), MG(9). C P G O ) , HTGI 9), 1 PCG(9)) C a l c u l a t e the C o o l i n g A1r I n l e t P r o p e r t i e s MG(IO) • MG(5) • (1.0 - MRAfE ) PG(10) " PG(7) TG(10) • TG(7) TYPE - 1 VEL - VS(1) CALL AIR(PGOO), TGOO), HGOO). SGOO). MGOO), CPG(IO). 1 HTGOO). PCGOO)) C a l c u l a t e the C o o l i n g A1r O u t l e t P r o p e r t i e s PG( 12) • P G O ) MGI12) • MGI10) TYPE - 1 VEL • VSI1) CALL AIRIPGI12). TG(12). HG(12), SG(12). MG(12), CPG(12), 1 HTGI12), PCG(12)) V S O ) - MG(12) / RHO / FAGl 12) HEAT 1 • MG(10) • (HGI12) - HGI10)) Check the PFB Heat Balance  181 182 183 184 185 186 187 188 189 190 191 192 193 194 195 196 197 198 199 200 201 202 203 204 205 206 207 208 209 210 211 212 213 214 215 216 217 218 219 220 221 222 223 224 225 226 227 228 229 230 231 232 233 234 235 236 237 238 239 240  TEMP-TEMP+IHPFB-HEAT1)/UA(1) IF (0ABS(HEAT1 - HPFB) .GE. 0.05) GO TO 150 C a l c u l a t e the P r o p e r t i e s o f the C o o l i n g A i r and Combustion Gas M i x t u r e PG( 13) - P G O ) TYPE - O CALL MIX(PG( 13). TG(13). HG(13), HG(12), H G O ) , SG(13). MG(13), 1 MG(12). M G O ) , CPG(13), HTGI 13). PCG(13)) C a l c u l a t e the P r o p e r t i e s o f Bypass and C o o l i n g A i r and Combustion Gas Mixture CALL MIX(PG(13). TG(13), HG13, HG(5), HG(13), SG(13), MG13, MGB, 1 MGI13). CPGI13), HTGI13), PCGl13)) HGI 13) • HG13 MG(13) • MG13 C a l c u l a t e the'H.P.Turbine O u t l e t P r o p e r t i e s WCOMP - M G O ) • ( H G O ) - HG(1)) ' SG(15) - SG(13) MG(15) • MG(13) HGI15) • HGI13) - WCOMP / NGT2 / MG(13) CALL GAHSIPGI15). TG(15). HG(15). SGI 15), MGI15), CPGI15), 1 HTG(15). PCG(15)) HGI15) • HGI13) - WCOMP / MG(13) CALL GASHlPGI 15), TGI 15). HGI 15), SG(15). MG(15), C P G O S ) , 1 HTG(15), PCGl15)) C a l c u l a t e the H.P.Turbine C h a r a c t e r i s t i c s SPEED2 • R0T1 / DS0RT(TG(13) + 273.1S) / N02 PR2 - PG(13) / PG(15) CALL GTISPEED2. MASS2, NGT2, PR2. PD2, EOS) MG13 - MASS2 / 0S0RT(TGO3) + 273.15) * P G O 3 ) • M02 IF (DABS(MG(13) - MG13) .GE. 0.0001) GO TO 120 C a l c u l a t e the L . P . T u r b i n e C h a r a c t e r i s t i c s SPEEDS - R0T2 / DSQRT(TG(1S) + 273.15) / ND3 PR3 - PG(15) / PG(18) CALL GT(SPEEDS, MASSS, NGT3, PR3, PDS. EDS) MG15 • MASSS / DSQRT(TG(15) • 273.15) • PG(15) * MD3 C a l c u l a t e the L . P . T u r b i n e O u t l e t P r o p e r t i e s MGI18) - MG(13) P G O B ) • .1013 + 0.0011 • ( (MG(1B)/MG18)**2) SG(18) - SG(15) CALL GASSIPGI18). TG(18), HGI18). SG(18). MG(18), CPGI18), 1 HTG(18), PCG(18)) HGI18) • HGI15) - NGT3 • (HG(15) - HOI 18)) TYPE - 2 VEL - 15.0 DIAM • 0.05 CALL GASHlPGI 18), TG(18), HG(18). SG(18). MG(18). C P G O B ) , 1 HTGI18), PCGl18)) C R0T1 - R0T1 • ((MG15/MG(15))**0.3) IF (0ABS(MG15 - MG(15)) . GT'.0.0001) GO TO 120 C C STEAM PORTION OF PROGRAM C TA1 • A(4) + A(5) C a l c u l a t e the Condenser O u t l e t P r o p e r t i e s TYPE ' O CALL P S A T ( P S O ) . TMIN) LL • 3 T S O ) - TMIN CALL STEAM(PSO). T S O ) . H S O ) . S S O ) , C P S O ) . H T S O ) . P C S O ) . 1 LL)  241 242 243 244 245 246 247 248 249 250 251 252 253 254 255 256 257 258 259 260 261 262 263 264 265 266 267 268 269 270 271 272 273 274 275 276 277 278 279 280 281 282 283 284 285 286 287 288 289 290 291 292 293 294 295 296 297 298 299 300  XS(1) " 0.0 C DIF » 0.1 MXO • 1 IZ - 1 MST • OMST INC » -MST / 10.0 C a l c u l a t e the B o i l e r P r e s s u r e and S a t u r a t i o n Temperature from the Steam Turbine C h a r a c t e r i s t i c s 160 PS(5) • MST • DSQRT(TSO) • 273.15) / FO PS(4) • PS(5) CALL TSAT(PS(4), T S ( 4 ) ) C a l c u l a t e the Superheater Heat T r a n s f e r CSC - (HS(5) - HS(4)) / (TS(5) - TS(4)) • MST CSH - (HG(19) - HG(18)) / (TG(19) - TG(18)) • MG(18) U(3) - 1.0 / <2.0/(HTG<18) • HTG(19)) + 2.0/(HTS(4) • HTS(5))) UA(3) - A O ) • U(3) 170 FORMAT ('#3 U(3),C3C,C3H»', SF10.5) OPT - 1 CALL EFFECT! TG( 18), TG(19), C3H. TS(4), T S O ) . CSC, UA(3), OPT) C a l c u l a t e the Superheater O u t l e t Gas Temperature PG(19) • PAMB MG(19) » MG(18) TYPE • 2 VEL • V G O ) CALL GAS(PG(19). TG(19), HG(19). SG(19), MG(19). CPG(19), 1 HTG(19). PCG(19)) V G O ) " MG(19) / RHO / FAG(19) C a l c u l a t e the Superheater O u t l e t Steam Temperature TYPE • 1 TS5 • T S O ) HS(5) • HS(4) + MG(18) / MST • (HG(18) - HG(19)) VEL - V S O ) LL • 2 CALL STATEH(PSO) . T S ( 5 ) . HS(5). SS(5), CPS(5). XS(5), HTS(5). 1 PCSO)) V S O ) - MST / RHO / F A S O ) Check to see If the Superheated Steam Temperature has Changed IF (DABS'TSO) - TS5) GE. 0.01) GO TO 160 C a l c u l a t e the B o i l i n g S a t u r a t i o n P r o p e r t i e s P S O ) • PS(4) CALL T S A T ( P S O ) . T S O ) ) VEL • VS(4) LL • 2 CALL STEAM(PS(4), T S ( 4 ) . HS(4). SS(4), CPS(4), HTS(4), PCS(4). 1 LL) XS(4) - 0.0 VS(4) - MST l/ RHO / FAS(4) TYPE - 4 VEL • V S O ) LL - 3 CALL STEAM(PSO). T S O ) , H S O ) , S S O ) , C P S O ) , H T S O ) , P C S O ) . 1 LL) X S O ) - 0.0 C a l c u l a t e the Feed Water Pump O u t l e t P r o p e r t i e s TYPE « 1 PSO) - PSO) CALL LI0S(PS(2), T S O ) . H S O ) , SS(1). C P S O ) , X S O ) . H T S O ) . 1 PCSO)) H S O ) - H S O ) • ( H S O ) - H S O ) ) . / NP  301 302 303 304 305 306 307 308 309 310 311 312 313 314 315 316 317 318 319 320 321 322 323 324 325 326 327 328 329 330 331 332 333 334 335 336 337 338 339 340 341 342 343 344 345 346 347 348 349 350 351 352 353 354 355 356 357 358 359 360  CALL L I Q H ( P S O ) . T S O ) . H S O ) , S S O ) . C P S O ) . X S O ) . H T S O ) , PCSO)) V S O ) • MST / RHO / F A S O ) C a l c u l a t e the Heat T r a n s f e r In the B o i l i n g S e c t i o n o f the HRSG C4C - 10CO00.0 C4H • ( H G O O ) - HG(19)) / ( T G O O ) - TG(19)) • MG(18) U(4) • 1.0 / (2.0/IHTGO9) + H T G O O ) ) • 1.0/HTSO)) UA(4) • U(4) * A(4) 180 FORMAT ('#4 U(4),C4C,C4H-', 3F10.5) OPT - 1 CALL EFFECT(TG( 19). TGI 20). C4H. T S O ) . T S ( 4 ) , C4C, UA(4). OPT) C a l c u l a t e the Gas P r o p e r t i e s C o r r e s p o n d i n g t o the Onset of B o i l i n g P G O O ) - AMB MGOO) • MG( 18) VEL - VG(4) TYPE • 2 CALL GAS(PGOO), T G O O ) . HG(20). S G O O ) . MGOO). CPGOO). 1 HTGOO), PCGOO)) V G O ) - MGOO) / RHO / FAG(20) C a l c u l a t e the Heat T r a n s f e r i n the Feed Water S e c t i o n o f the HRSG C5C • ( H S O ) - H S O ) ) / ( T S O ) - T S O ) ) • MST C5H - ( H G O O - H G O O ) ) / (TG(21) - T G O O ) ) * MG(18) U(5) • 1.0 / (2.0/(HTG(20) + H T G O O ) + 1.0/HTSO)) UA(5) - U(5) * A(5) 190 FORMAT ('#5 U(5),C5C,C5H"'. 3F10.5) OPT - 1 CALL EFFECT(TG(20) . T G O O . C5H, T S O ) . T S O ) , CSC, UA(5). OPT) C a l c u l a t e the S t a c k I n l e t Gas P r o p e r t i e s 200 P G O O - PAMB MG(21) • MG(18) VEL • V G O ) CALL GAS(PG(21), T G O O . H G O O , SG(21). M G O O . C P G O O . 1 HTGOO, PCGOO) V G O ) • M G O O / RHO / F A G O I ) R e - E s t i m a t e the Steam Mass Flow MS4 - MG( 18) • (HG(19) - H G O O ) ) / (HS(4) - H S O ) ) MSS • MG(18) * (HGOO) - H G O O ) / ( H S O ) - H S O ) ) MST • (MS4 • MS5) / 2.0 C0NV1 - C0NV2 R e d i s t r i b u t e t h e Heat T r a n s f e r Areas A4 • A(4) A5 - A O ) 210 A(4) - A4 • MST / MS4 A(5) - A5 • MST / MS5 TA2 - A ( 4 ) + A(5) A(4) - TA1 / TA2 • A(4) A O ) • TA 1 / TA2 • A(5) C0NV2 - A O ) - A5 IF ((C0NV1«C0NV2) .GE. 0.000) GO TO 220 A(4) - ( A ( 4 ) + A4) / 2.0 A O ) - ( A ( 5 ) + A5) / 2.0 220 CONTINUE C IF (0ABS(MST - MS4) . GE. 0.0005) GO TO 160 IF (DABS1MST - MS5) .GE. 0.0005) GO TO 160 C a l c u l a t e the Steam T u r b i n e O u t l e t P r o p e r t i e s PSO) - PSO) CALL STATES(PS(6). T S ( 6 ) . H S O ) , S S O ) , CPSO)', X S O ) , H T S O ) , 1 PCSO)) H S O ) - H S O ) - NT * ( H S O ) - H S O ) ) 1  p  —* (JI VO  361 362 363 364 365 366 367 368 369 370 371 372 373 374 375 376  End o f f i l e  1  CALL STATEH(PS(6), TS(6), HS(6). SS(6). CPS(6), XS(6), HTS(6). PCS16))  C a l c u l a t e the C y c l e Performance 240  HEAT * MF * HCO WGT > MG(15) * (HG(15) - HG(I8)> WST - MST • (HS(5) - HS(6)) WP - MST * (HS(2) - H S ( D ) + 1.3 • MST WORK • WGT • WST - WP EFFO - EFF EFF - WORK / HEAT * 100 WR • WGT / WORK * 100 360 CONTINUE STOP END  o  i  Pulverized Coal B o i l e r Plant  a  Design Load Analysis  2 5 e 7 8 9 10 11 12 13 14 IB 16 17 18 15 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60  C  C  C C  IMPLICIT REAL'S (A-H.O-Z) REAL'S TGOO.PG(21),HGOO.SG(21),MGOO.CPGOO,LMT3 -,NGT,NGC, NP ,NT ,NI ,MF.MST1,MST,LAMBOA,MU,KT.MSOL,MLIME -,PS(1S).TS(1S),HS(15),SS(I5),XS(1S),CPS(15).FAG(21).FAS(15) -,HTS(15).PCS(15),PCG(21),HTG(21),UA(9),U(9),A(9),MS(15) COMMON /AREA1/ CN.HM.00.SU.NI.ASH.H20.HFO,LAMBOA,MF.TS03 COMMON /AREA3/ HSOL.TSO,MSOL.MLIME TSO-328.0 LL-1 CALL STEAM(MU.MU,MU.MU,MU,MU,MU,LL)  MST-1.0 DO 752 IH-1,IS TS(IH)-0.00 PS(IH)-0.0 HS(IH)-0.0 SS(IH)-0.0 XS(IH)'0.0 CPS(IH)"0.0 HTS(IH)-0.0 752 CONTINUE XS(14)-1.0 C Read In Fuel Data READ(6,600)HFO,HCO.CN.HM,00,SU.NI,ASH,H20 600 F0RMAT(2F12.2,7F1B.9) C NT"0.89500 NP-0.81D0 C C a l c u l a t e Ambient A i r P r o p e r t i e s PG(1)>0.1013 TG(1)-15.0 MG(1)-1.0 CALL A1R(PG(1),TG(1),HG(1),SG(1).MG(1).CPG<1),HTG(1),PCG(1)) C C a l c u l a t e A1r P r o p e r t i e s a t A i r Preheater E x i t / Burner I n l e t PG(2)-PG(1) MG(2)-1.0 TG(2)»218.0 CALL AIR(PG(2),TG(2).HG(2),SG(2).MG(2).CPG(2).HTG(2),PCG(2)) C C a l c u l a t e Gas P r o p e r t i e s a t B o i l e r Outlet LAMBDA-1.1 TG(8)-328.0 PG(8)-PG(2) LZ-0 CALL BED(HG(2),MG(2),PG(B),TG(S).HG(8),SG(8),MG(8),HPFB,CPG(8) -,HTG(8),PCG(S),LZ) C C a l c u l a t e Gas P r o p e r t i e s a t A i r Preheater Outlet TG(10)•161.57 PG( 10)-0.09687 MG(10)-MG(8) CALL GAS(PG(10),TG(10).HG(10),SG(10),MG(10),CPG(10),HTG(10) -, PCGOO)) C C a l c u l a t e Gas P r o p e r t i e s a t Fan O u t l e t  61 62 63 64 65 66 67 68 69 70 71 72 73 74 73 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 107 108 109 110 111 112 113 114 115 116 117 118 119 120  PGOO-O.1013 SG(11)«SG(10) MG(11)«MG(10) CALL GASS(PGOO.TG(11).HGOO.SG(11).MGOO.CPGOO.HTGOO -.PCGOO) HG(11)«HG(10)+(HG(11)-HG(10))/0.80 CALL G A S H ( P G O O , T G O O . H G O O . S G O O , M G O O , C P G O O , H T G O O -.PCGOO)  C C STEAM PORTION OF PROGRAM C C C a l c u l a t e Steam P r o p e r t i e s a t t h e Superheater I n l e t PS(14).18.065 CALL TSAT(PS(14),TS(14)) LL-2 CALL STEAM(PS04).TS(14).HS(14),SS(14),CPS04),HTSO4).PCS04) -.LL) C C a l c u l a t e Steam P r o p e r t i e s a t the Superheater O u t l e t 77 PS(1)-16 893 TSO)-S37.8 LL-2 CALL S T E A M ( P S O ) . T S O ) . H S O ) , S S O ) , C P S O ) . H T S O ) . P C S O ) , L L ) XSCO-1.0 C C a l c u l a t e Steam P r o p e r t i e s a t t h e Reheater I n l e t PS(3)-4.1850 SS(3)-SSO) CALL STATES(PS(3),TS(3).HS(3),SS(3),CPS(3),XS(3),HTS(3),PCS(3)) HS(3)-HSO)-NT'(HSO)-HS(3)) CALL STATEH(PS(3),TSO).HSO).SSO).CPSO),XS(3).HT'S(3),PCSO)) CALL TSAT (PS(3).TS(13)) C C a l c u l a t e steam P r o p e r t i e s a t the Reheater O u t l e t TS(4)-537.8 PS(4)-4.013 XS(4)-1.0 LL-2 CALL STEAM(PS(4).TS(4).HS(4).SS(4),CPS(4).HTS(4),PCS(4).LL) C C a l c u l a t e Steam P r o p e r t i e s a t t h e Condenser I n l e t TMIN-38.32 CALL PSAT(PLOW.TMIN) PS(5)-PL0W SS(5)-SS(4) CALL STATES( PS< 5 ).TS(5), H S O ) . S S O ) . C P S O ) . X S O ) . H T S O ) , P C S O ) ) HS(5)-HS(4)-NT'(HS(4)-HSO)) CALL STATEH(PSO) . T S O ) , HS( 5 ) , SS( 5) ,CPS( 5 ) . XS( S) ,HTS(5 ) , PCS(5 )) CPS(S)-0.0 C C a l c u l a t e Steam P r o p e r t i e s a t the Condenser O u t l e t PS(6)-PL0W TS(6)»TMIN LL-3 CALL STEAM(PS(6),TS(6),HS(6).SS(6),CPS(6).HTS(6).PCS(6).LL) C C a l c u l a t e #1 Feed Hater Heater Performance TS(8)-144.66 CALL P S A T ( P S O ) . T S O ) ) LL-3 CALL STEAM(PSO).TS(8).HS(8).SS(8).CPS(B).HTS(S).PCSO) -.LL) C PS(12)-PS(S) SS(12)-SS(4) CALL STATES! PS( 12 ) , TSO 2 ) , HS(12 ) . SS( 12),CPS( 12 ). XS(12 ) . HTS02 )  121 122 123 124 125 126 127 128 129 130 131 132 133 134 135 136 137 138 139 140 141 142 143 144 145 146 147 148 149 150 151 152 153 154 155 156 157 158 159 160 161 162 163 164 165 166 167 168 169 170 171 172 173 174 175 176 177 178 179 180  C  -,PCS(12)) HS(12)-HS(1)-NT*(HS(4)-HS(12)) CALL STATEH(PS(12),TS(12),HS(12).SS(12).CPS(12),XS(12),HTS(12) -,PCS(12))  PS(7)-PS(12) SS(7)»SS(6) CALL LI0S(PS(7),TS(7),HS(7).SS(7).CPS(7).XS(7).HTS(7),PCS(7)) HS(7)-HS(6)+(HS(7)-HS(6))/NP CALL LI0H(PS(7),TS(7),HS(7).SS(7),CPS(7),XS(7),HTS(7),PCS(7)) C C a l c u l a t e #2 Feed Water Heater Performance TS(10)-252.0 CALL PSAT(PS(10).TS(10>) LL«3 CALL STEAM(PS<10),TS(10),HS(10),SS(10),CPS(10).HTS(10),PCS(10) -.LL) C PS(9)-PS(10) SS(9)-SS(8) CALL LIQS(PS(9).TS<9).HS(9),SS(9).CPS(9),XS(9),HTS(9),PCS(9)) HS(9)-HS(8)+(HS(9)-HS(8))/NP CALL LIQH(PS(9).TS(9),HS(9).SS(9).CPS(9).XS(9).HTS(9).PCS(9)) C PS(13)-PS(14) SS(13)-SS(10) CALL LI0S(PS(13).TS(13),HS(13).SS(13),CPS(13),XS(13),HTS(13) -,PC5(13)) HS(13)"HS(10)*(HS(13)-HS(10))/NP CALL LI0H(PS(13),TS(13).HS(13).SS(13),CPS(13),XS(13),HTS(13) -,PCS(13)) C TS(tl)-TSO) PS(11)-PS(3) HS(H)-HSO) SS(11)-SS(3) C C a l c u l a t e Mass Flows through the Feed Water Heaters and B o i l e r FWH1-(HS(10)-HS(9))/(HS(11)-HS(9)) FWH2-(HS(8)-HS(7))/(HS(12)-HS(7))•(1-FWH1) HSTE-HS(1)-HS(13)+<HS(4)-HS(3))*(1-FWH1) MST-HPFB/HSTE C 75 DO 156 1-1. 14 MS(I)-MST 156 CONTINUE DO 157 1*3.9 MS(I)=MST*(1-FWH1) 157 CONTINUE DO 158 1-5,7 MS(I)-MST*(1-FWH1-FWH2) 158 CONTINUE MSOO-FWH1-MST MS(12)-FWH2*MST C C C a l c u l a t e C y c l e Performance Data C HEAT-MF -HCO WST-MS(1)*(HS(1)-HS(3))*MS(4)•(HS<4)-HS(5))-MS<12)*(HS(4)-HS(12) -) WP-MS(7)«(HS(7)-HS(6))+MS(13)-(HS(13)-HS(10))*MS<9)* -(HS(9)-HS(8))*MG(10)«(HG(11)-HG(10))  181 182 183 184 C 185 186 End o f f i l e  WORK-WST-WP EFF-WORK/HEAT*IOO WR-WGT/WORK*100 STOP END  1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60  ciiimiimiiiiuiiiiiiiii C/// THERODYNAMIC AND///// C//// HEAT TRANSFER ///// C///// LIBRARY ////// C////////////////////////// C C PART 1 C C///////////////////// C////// COAL /////// C/// COMBUSTION //// C// AND GAS //// C// THERMODYNAMICS /// C///////////////////// C C C/////////// C// A I R // C/////////// C SUBROUTINE AIR(P.THETA,H,S.MASS,CP.HTC,VSI) C IMPLICIT REAL»8 (A-H.O-Z) REAL*8 X(2),CPG(2),DH(2).SE(2),MU,KT,MASS,CC(2) C T=THETA+273.15D0 INTEGER TYPE C COMMON /AREA2/ VEL,RHO.AREA.OIAM.MU.KT.PR,REY.EPS.TYPE C LX0=1 RMOL-8.314 GOTO 16 C///////////// C// A I R H // C///////////// ENTRY AIRH(P.THETA,H,S.MASS.CP.HTC,VSI) C LX0=2 H2=H T=900.0 GOTO 16 C///////////// C// A I R S // C///////////// ENTRY AIRSIP.THETA,H,S.MASS,CP.HTC,VSI) LX0=3 S2=S T«90O0 C 16 X(1)*MASS*0.0273832 X(2)=MASS*0.007278884 SUMX=X(1)+X(2) CC(1)=X(1)/SUMX CC(2 >=X(2)/SUMX 17 TT-T/100.0 TJ=T/1000.0 C C CALCULATE CP VALUES C  61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 107 108 109 1 10 111 112 113 1 14 I 15 116 117 118 1 19 120  C C C  C C C  C  CPGI 11=39.060-512.79'(TT*»(-1.5)1+1072.7*(TT*«(-2)) --B20.4*(TT»»(-3)) CPGI2 I=37.432*0.020102*(TT**1.5)- 178.57*(TT*•(- 1.5)) -+236.88*<TT**(-2)) CP»(X(1)<CPG(1)+X(2)*CPG(2))/MASS CALCULATE ENTHALPY DH(1)=(<3.344*T+2.943E-04*(T«*2)+1.9S3E-09*(T**3) 1-6.575E-12*(T**4))-1029.7)*RMOL DH(2)=((3.253*T+6.524E-04*(T**2)-1.495E-07*(T**3) 1+1.539E-11«(T«*4))-1030.7)*RMOL H=(X(1)*DH(1)+X(2)*DH(2))/MASS IF (LX0.NE.2) GOTO 515 T2=T+(H2-H)/CP IF(DABS(H2-H).LE.0.01) GOTO 515 T-T2 GOTO 17 CALCULATE ENTROPY 515 SE(1)=152.692+178.359*TJ-192.848*(TJ*«2)+119.242*(TJ**3) --29.3123MTJ«*4) SE(2)=166.619+173.963*TJ-180.068*(TJ**2)+110.388*(TJ**3) --27 3588*(TJ**4) SM*X(1)»SE(1)*X(2)*SE(2)-RM0L*(X(1)*DLOG(CC(1))+X(2)*DLOG -<CC<2))) R = RMOL'SUMX/MASS S=SM/MASS-R«0L0G(P/O.1013) IF (LX0.NE.3) GOTO 516 T2=T'DEXP((S2-S1/CP) IF(0ABS(S2-S).LE.0.OO05) GOTO 516 T=T2 GOTO 17  516 MU=0.00669/(T+117 9)*((T/273.15)**1.5) KT"(0.33017+8.265*(T/1000.0)-1.813*((T/1000.0)**2))•1.OE-2 RHO=P/(R*T)«1000.0 PR=MU*CP/KT*1000.0 REY=RHO*VEL*DIAM/MU VSI=1.0 IF (TYPE.E0.1) HTC=KT/DIAM*0.023*(REY**0.8)*(PR**0.33) IF (TYPE . EO . 2 ) HTC=KT/DI AM«0. 33* ( REY**0.6 ) • (PR**0. 3 ) THETA=T-273.15 RETURN END C/////////// C// B E D / / C/////////// C SUBROUTINE BED(H1.M1,P,THETA,H,S,MASS,HEAT.CP.HTC,VSI,LZ) C IMPLICIT REAL'S (A-H.O-Z) T = THETA+273. 15D0 C REAL'8 M1,MASS.MF,DH(11).CPG(11).UUU<11),SE(7) -.KS02.N1,LIMEF,NCONV,MOLRAT,N2I,NOC.MA.MG.MU,KT -.X(11),CC(11),V(4),KTT(4),M<4),0(4.4).LAMBDA C INTEGER TYPE  —* CTi OJ  12 1 122 123 124 125 126 127 128 129 130 131 132 133 134 135 136 137 138 139 140 141 142 143 144 145 146 147 148 149 150 151 152 153 154 155 156 157 158 159 160 161 162 163 164 165 166 167 168 169 170 171 172 173 174 175 176 177 178 179 180  C C C C C  C  COMMON /AREA 1/ COMMON /AREA2/  CN.HM.00,SU.NI,ASH.H20,HFO,LAMBDA.MF.TS03 VEL,RHO,AREA.DIAM.MU.KT,PR,REY.EPS.TYPE  CALCULATE MOLES OF CONSTITUENTS BEFORE COMBUSTION N2I:N2. 021:02. FUEL. CAC03I:LIMESTONE LXQ=1 RM0L=>8.314D0 N2I"M1»0.0273832D0 021=M1*0.00727888400 IF (LZ.EO.1)FUEL*MF/100.0DO IF ( LZ.EQ.0)FUEL*021/LAMBDA/(CN+HM/4.ODO-00/2.ODO+SU+NI/2 MF=FUEL*100.0D0 . HFOL--1207700.000 TC-T-273.1500  C  C C  c c c c  c c c c c  c c c  BURNUP =0.99D0 LIMEF*0.85D0 NCONV-0.70D0 MOLRAT-2 .000 CAC03I*FUEL«SU*M0LRAT N2;1  02;2  CAC03;8  C02;3 CAS04;9  H20;4  NO;5 ASH;10  S02;6  S03;7 COAL;11  X( 10)=BURNUP*FUEL*ASH X(3)»FUEL*(BURNUP*CN+LIMEF*SU) S02"FUEL*SU*(BURNUP-LIMEF) X(1)=N21 + (FUE L *NI* <BURNUP-NCONV))/2 X(5)*NC0NV*FUEL*NI X(4)=BURNUP*FUEL*(HM/2+H20) X(9)=FUEL*SU«LIMEF 02=BURNUP«FUEL*(0O/2-HM/4)+02I-X(3)-X(9)/2-SO2-X(5)/2 X(B)-FUEL«SU*(MOLRAT-LIMEF) X(11)»(1-BURNUP)*FUEL HREACT=FUEL*HF0+H1*M1+CAC03I*HF0L TT=T/100.0 TJ'T/1000.0 SOLID COMPONENT THERMODYNAMIC PROPERTIES : DH-ENTH  CPG-CP  DH(8)=4.184*(19.68*T+0.005945*T«T+307600/T-7463.8) DH(9)=4.184*(18.52'T+0.0109B5*T«T*156B00/T-7066.9> DH(10)"4.184«(17.09*T+0.000227*T*T+897200/T-813B.1) DH(11)=•141.5*(T-298.0) CPG(8)=4.184*(19.68+0.01189*T-307600/T/T) CPG(9)=4.184*(18.52+0.02197«T-156800/T/T) CPGI10)=4.184*117.09*O.O0O454*T-89720O/T/T) CPGI11)»141.5 HEAT OF FORMATION OF COMPONENTS UUU(1)=0.0 UUU(2)=0.0  181 182 183 184 185 186 187 188 189 190 191 192 193 194 195 196 197 198 199 200 201 202 203 204 205 206 207 208 209 210 211 212 213 214 215 216 217 218 219 220 221 222 223 224 225 226 227 228 229 230 231 232 233 234 235 236 237 238 239 240  UUU(3)=-393522.0 UUUI4 ) = -241827.0 UUU(5)=90417.0 UUU(6)»-297040.0 UUUI 7) =--396030.0 UUU(8) = -121 1268.0 UUU(9)=-14O3816.0 UUU(10)=0.0 UUU(11)=HF0 HLL-X(8)*(DH(B)-121126B.O)+X(9)*(DH(9)-1403816.0)+Xl10)*DH(10) -+X(11)*(0H(10)+HF0) GOTO 17 C///////////// CI I G A H S // C///////////// ENTRY GAHS(P,THETA,H,S.MASS,CP.HTC.VSI) LX0=6 S2=S H2*H P-0.7 T*900.0 GOTO 17 C/////////// CI I M I X / / CIII///I//II ENTRY MIX(P,THETA,H.HA,HG.S.MASS,MA.MG.CP,HTC.VSI) C MASS=MA*MG H=>(HA*MA+HG*MG)/MASS X(1)-X(1)+MA*0.0273832 02*02+MA*0.007278884 Cllllll/llllll C/l G A S H / / C///////////// ENTRY GASH(P.THETA.H.S,MASS.CP,HTC.VSI) C LXQ=2 H2=H T*9CO.O GOTO 17 C///////////// CII G A S S // Clllllllllllll ENTRY GASSiP.THETA.H.S,MASS,CP,HTC,VSI) LXQ=-4 S2=S T=900.0 GOTO 17 Cl/ll/llllll C/l GAS// Clllllllllll ENTRY GAS(P,THETA,H,S,MASS.CP,HTC.VSI) T=THETA+273.15D0 C LXQ=3 C C GAS COMPONENT THERMODYNAMIC PROPERTIES; DH-ENTH CPG-CP SE-ENTHPY C 17 TT=T/10O.O Td = T/1000.0  241 242 243 244 245 246 247 248 249 250 251 252 253 254 255 256 257 258 259 260 261 262 263 264 265 266 267 268 269 270 271 272 273 274 275 276 277 278 279 280 28 1 282 283 284 285 286 287 288 289 290 291 292 29» 294 295 296 297 298 299 300  C C C  C  DISSOCIATION REACTION: S02 + 1/2 02 " SO3 KSD2=DEXP(9.8471-16.3392«Td+4.7273*(Td**2 ) ) SUMX=X(1)+02+X<3)+X<4)+X(5)+S02 SK=KSD2*DSQRT(02/SUMX) X(7)»SK/( 1+SK)*S02 X(6)=S02-X(7) X(2)-02-X(7)/2 SUMX=X(1)+X(2)+X(3)+X(4)+X(S)+X(6)+X(7) 179 IV=1.7 CC(IY)=X(IY)/SUMX 179 CONTINUE DO  C  C  C  CPG(11=39.060-512.79*<TT**(-1.5))•1072.7*(TT**(-2)) --820.4*(TT*«(-3)) CPG(2)=37.432+0.020102*(TT»«1. 5) - 178 . 57* ( TT** < - 1 . 5 ) ) -+236.BB*(TT**(-2)) CPG(3)--3.7357+30.529»(TT"(0.5))-4. 1034*TT+0.024198* (TT* *2 ) CPG(4)=143.05-183.54*(TT**(0.25))+82.751*(TT**(0.5>) --3.69BB9*TT CPG(5)=59.283-1.7O96*(TT**0.5)-7O.613*(TT**(-0.5)) -+74.889*(TT*«(-1.5)) CPG(6)=4.1868*(5.8257+15.S095*TU-11.2842*(Td**2)+2.9751*(Td«*3) CPG<7)=4.1868«(4.2157+35.6419*Td-35.5649*(Td**2)+17.065*(Td*«3) --3.20*(Td**4)) CP=0.0 DO 192 1-1.7 CPP=X(I)*CPG(I) CP-CP+CPP 192 CONTINUE IFd.XO.EO.1) MASS-X(3)*44.01+X(4)*18.02+X(6)*96.0 -+X(2)*32.0+X(1)«28.01+X(7)«112.0+X(5)*30.0 CP-CP/MASS DH( 1)-((3.344«T+2.943E-04*(T**2)+1.953E-09«(T**3) 1-6.575E-12*(T*«4))-1O29.7)*RM0L DH(2)-((3.253*T+6.524E-04«(T**2)-1.495E-07*(T**3) 1+ 1 . 539E - 1 1*',T**4 ) )- 1030. 7 )*RM0L DH(3)-((3.096*T*O.0O273*(T**2)-7.885E-O7*(T«*3) 1+8 . 66E-11*(T**4))-1153.91)«RMOL DH(4)-((3.743«T+5.656E-04*(T**2)+4.952E-08*(T**3) 1-1.818E-11«(T**4))-1175,0)*RMOL DH(S)=((3.502«T+2.994E-O4*(T**2)-9.59E-09«(T**3) 1-4.904E-12*(T**4()-1077,4)«RM0L DH(6)=4186.8«(-2.2956+5.6001«Td+8.2162*(Td**2)-4.1531*(Td**3) 1+0.8615*<Td**4)) DH(7)=4186.8«(-2.73+5.5187«Td+14.2107*(Td**2)-7.2269*(Td**3) 1+1 4769*(Td*«4)l H=0.0 00 190 1-1,7 H=H+(X(I)«(UUU(I)+DH(I)))/MASS 190 CONTINUE IF (LX0.NE.2) GOTO 800 T2=T+(H2-H1/CP IF(DABS(H2-H).LE.0.01) GOTO 800 T-T2 GOTO 17  301 302 303 304 305 306 307 308 309 3 10 31 1 312 313 314 315 316 317 318 319 320 321 322 323 324 325 326 327 328 329 330 331 332 333 334 335 336 337 338 339 340 341 342 343 344 345 346 347 348 349 350 351 352 353 354 355 356 357 358 359 360  C  C  C C C C  C  )=152.692+178.359*Td-192.848*(TJ**2)+119.242*(Td* •3) 800 SE( 1 --29.3123*(Td**4) SE(2(=166.619+173.963*Td-180.068*(Td**2)+110.388*(Td* *3) --27.3588«(Td**4) SE(3)=167.043+199.3B2«Td-168.107*(Td**2)+92.482* ( Td«*3) --21.4962*(Td**4) SE(41=144.602+200.381*Td-209.495*(Td**2)•128.447*(Td* •3) --31.2672*(TJ**4) SE(5)=171.329+179.934«Td-192. 140*(Td**2)•118.696*(Td* •3) --29.3130*(Td**4) SE(61=197.977+215.217*Td-185.761*(Td**2)+101.649*(Td**3) --23.4504»(Td**4) SE(71=195.207+253.367*Td-181.854*(Td**2)+85.576*(Td** 3) --17.5878*(Td**4) S=0.0 DO 191 1=1,7 S=S+X(I)*(SE(I)-RMOL*OLOG(CC(I))) 191 CONTINUE R=RMOL*SUMX/MASS S-S/MASS-R*DLDG(P/0.1013) IF (LX0.NE.4) GOTO 516 T=T*DEXP((S2-S)/CP) IF(DABS(S2-S).LE.0.0005) GOTO 517 GOTO 17 516 IF (LX0.NE.6) GOTO 517 T=T+(H2-H)/CP P=P«DEXP((S-S2)/R) IF(DABS(H2-H).GE.0.01) GOTO 518 IF(DABS(S2-S).LE.0.0005) GOTO 517 518 GOTO 17 517 IFUXO.EQ. 1 ) HEAT-HREACT-HLL-(MASS*H) CALCULATE VICOSITY  AND  THERM COMD OF MIXTURE  142 V(4)=0.OO843/(T+659.)•((T/273.15)**1.5) V(1)"0.019105/1T+109.17)*((T/573.15)«*1.5) V(2)=0.02319/(T+129.68)*((T/573.15)**1.5) V(3)»O.021485/(T+246.88)*((T/573.15)**1.5) KTT(1)=(0.64962+6.495O2*Td-0.34385*Td*Td)«1.OE-2 KTT(2)=(0.12902+8.69427*Td-1.29194*Td*Td)«1.OE-2 KTT(3)=(-0.9856+9.36112*Td-1.63333«Td*Td)•1.OE-2 KTT(4)-(-0.3226+6.74690*Td+2.37502*Td*Td)* 1.OE-2 M(3)=44.01 M(1)=28.013 M(2)-31.999 M(4)=18.015 DO 450 1=1.4 00 451 d=1.4 0(I.d)=(1+(0S0RT(V(I)/V(d))*(M(d)/M(I))*«0.25))**2 •/(DS0RT(8.O*(1+(M(I)/M(d))))) 451 CONTINUE 450 CONTINUE MU=0.0 KT=0.0 DO 460 1=1,4 A= 1 .0  361 362 363 364 365 366 367 368 369 370 37 1 372 373 374 375 376 377 378 379 380 381 382 383 3B4 385 386 387 388 389 390 391 392 393 393.5 394 395 396 397 398 399 400 401 402 403 404 405 406 407 408 409 4 10 4 1 1 4 12 4 13 4 14 4 15 416 4 17 4 18 419  C C C  DO 461 J-1 ,4 1F(I.EQ.J) GOTO 499 A=A+(0(1.J)*CC(1)/CC(J)) 499 CONTINUE 461 CONTINUE MU=MU+(V(I)/A) KT=KT+(KTT(I)/A) 460 CONTINUE CALCULATE FLUID DYNAMIC AND HEAT TRANSFER DATA  RHO-P/(R-T)«1000.0 PR-MU-CP/KT-1000.0 REY-VEL*DIAM*RHO/MU VSI-1 0 IF (TYPE.EQ.1) HTC«KT/DIAM»0.023*(REY*'O.B)*!PR**0.33) IF (TYPE.EQ.2) HTC»KT/DIAM»0.33*(REY»*0.6)*(PR«»0.3) IF (TYPE.EQ.3) GOTO 211 GOTO 2 12 211 OP-0.001 ARCH-10000.0*RHO*(DP* *3)/(MU**2) EMF-O.42 UMF-MU/RHO/DP*(DSQRT(637.6+0.0651 *ARCH)-25.25) EPS=EMF»VEL/(1,05»VEL*EMF+UMF«(1.O-EMF)) OEL-(EPS-£MFI/<1 O-EMF) HTC1-( 1 O-DEL)«KT/DIAM«(5.0+0.05*<REY»*0.92)*PR) HTCO-KT/DIAM«0.33*(REY««0.6)»(PR**0.3) USD-O.18«(1-EPS) HTC-HTCO*(1.0+10 O0015/DP)«(1000.0*USD/RHO/VEL)) C WRITE(3.400) ARCH,UMF,EPS,DEL,HTC1,HTCO 400 FORMAT(/' ARCHEMDS* UMF VOID FRACT BUBL FRACT HTC1' HTCO '/.E12.2'.F10.5.2F12.6,2F10.2/) 212 CONTINUE C WRITE(3,401) P,T,RHO.VEL,PR,REY,VSI,HTC 401 FORMAT ( ' PRESS TEMP DENS VEL PRANDL ', REYNOLDS PRESS COEF H.T. COEF'/.FB.4,FB.2.2F8.3.F8.4 -,F12.1.F12.8.F12 2///) NOC-CC ( 5 ) • 10OOOOO. 0 S02C-CC(6)» 1000000.0 S03C-CC( 7 ) MOOOOOO. 0 TS03-114.885+6.S1275*0L0G(S03C)+0.405189»(DL0G(SO3C)**2) C WRITEO.901) N0C.S02C,SO3C.TS03,T 901 FORMAT(//'POLLUTANTS NOX'.FS.I,' PPM S02',F8.1,' PPM '. -'S03',F8. 1 ,' PPM'/,'CONDENSATION TEMP:'.F6.0,' C GAS TEMP:'. -F6.0//) THETA-T-273.15 RETURN END C C C PART 2 C  c//////////////////////// C/// C/// CI1/  HEAT EXCHANGER /// AND /// TURBINE ROUTINES ///  C/l11/11llllIII/Illllllll  C  c c  ////////////////////  420 42 1 422 423 424 425 426 427 428 429 430 431 432 433 434 435 436 437 438 439 440 44 1 442 443 444 445 446 447 448 449 450 451 452 453 4 54 455 456 457 458 459 460 461 462 463 464 465 466 467 468 469 4 70 471 472 473 474 475 476 477 478 479  c  // E F F E C T /// C //////////////////// C C SUBROUTINE EFFECT(TA1.TA2.CA,TB1.TB2.CB.UA.OPT) C REAL'8 TA1,TA2,TB 1 .T82,CA.CB,UA.C.CMIN,EFF.N INTEGER OPT C C CALCULATE CMIN AND C C IF(CA.LE.CB) GOTO 20 CMIN-CB C-CB/CA GOTO 30 20 CMIN-CA C-CA/CB C C CALCULATE NTU (N) AND EFFECTIVENESS ( E F F ) C 30 N-UA/CMIN 1F(C.LT.0.0O1) GOTO 40 EFF = ( 1 .0-OEXP(NMC-1 .0) ) )/( 1 ,0-C-DEXP(N-(C- 1 .0) ) GOTO 50 40 EFF- 1 0-OEXP(-N) SO 1 F ( 0 P T . E Q 2 ) GOTO 60 C OPT-1 SOLVE FOR TA2 c  c  TA2-TA1-CMIN/CA-EFF-(TA1-TB1) RETURN  c c c  OPT-2  c c c c c c  //////////////////// // H T X C H G /// ////////////////////  c  60  SOLVE FOR TB2  TB2»TB1+EFF*CMIN/CB»(TA1-TB1) RETURN END  SUBROUTINE HTXCHGfTA1,TA2.CA,TB1.TB2.CB,UA,OPT) REAL*8 TA2.TB2,CA.CB,UA,C,CMIN,EFF,N,TA1,TBI INTEGER OPT  c c c  CALCULATE CMIN AND C  c c c  OPT-1  lF(CA.LE.CB) GOTO 20 CMIN-CB C-C8/CA GOTO 30 20 CMIN'CA C-CA/CB 30 IF(0PT.EQ.2) GOTO 40 KNOW TA2  480 481 482 483 484 485 486 487 488 489 490 491 492 493 494 494.7 495 496 497 498 499 500 501 502 503 504 505 506 507 508 509 510 511 512 513 514 515 516 517 518 519 520 521 522 523 524 525 526 527 528 529 530 531 532 533 534 535 536 537 538  EFF=CA/CMIN«(TA1-TA2)/(TA1-TB1) IF (EFF.GT.1 0D0) GOTO 80 GOTO 50 C C OPT-2 KNOW TB2 C 40 EFF=CB/CMIN'(TB2-TB1)/(TA1-TB1) C C CALCULATE NTU AND U*A C 50 IF(C.LE.0.001) GOTO 60 N-1.0/(C-1.O)*DL0G((EFF-1.0)/((C*EFF)-1.0)) GOTO 70 60 N=~DLOG(1.O-EFF) 70 UA=N*CMIN 400 FORMAT!'EFFECT: C , CMIN. UA . NTU, EFF ' , 5F 10. 4 ) RETURN 80 WRITE(3,300)TA1.TA2.T81,TB2,CA,CB.OPT 300 FORMAT(//'***HTXCHGR EFF GTR THAN 1***',/' TA1 TA2 -'TBI TB2 CA CB OPT',/4F8.2.2F 11.3,15//) STOP END C C/////////////////// C//GAS COMPRESSOR/// C// G C /// C/////////////////// C SUBROUTINE GC(SPEED.MASS.EFFCY.PRATIO.POES.EDES,PSUR) C IMPLICIT REAL'S (A-Z.) C A 1-1.22385022D0'(PDES-1. O)» ( S P E E 0 " 2 . 51 )/( 7 .0'( 1. 0+SPEEO"2 .98 ) ) B1=8 ODO+7 0 D 0 * ( S P E £ D " 2 .98) C1-4.0DO+3.5DO«(SPEED«'2.98) PRATIO-1.00+A1'(B1*DSORT(MASS/!SPEED-.2))-(MASS/(SPEED- 2 ) ) * * C t ) C N0=(0.75+0.19*DS0RT(SPEED)-0.087*(SPEED**10.75))*EDES/0.83094899 B-3.9+0.011*DEXP(8.0*SPEED) M0=1.I'SPEcD-O.13 EFFCY-N0/(B-1.ODO)*(B*MASS/MO-<(MASS/MO)* *B)) C PSUR=(1.0+3.5*((MASS)"1.532))*PDES/3.90 300 FORMAT (4F14.6) IF (PRATIO.GE.PSUR) WRITE (4.400) 400 FORMAT!'"•" COMPRESSOR SURGING •••••') C RETURN END C//////////////// C//GAS TURBINE/// C// G T /// C//////////////// C SUBROUTINE GT(SPEED.MASS.EFFCY.PRESS,PDES.EMAX) C IMPLICIT REAL*8 (A-Z) C PRAT-1.0+3.0*!PRESS-1.0)/(PDES-1.0) C  539 540 541 542 543 544 545 546 547 548 549 550 551 552 553 554 555 556 557 558 559 560 56 1 562 563 5G4 565 566 567 568 569 570 57 1 572 573 574 575 576 577 578 579 580 581 582 583 584 585 586 587 588 589 590 591 592 593 594 595 596 597 598  C  B=DEXP(6.332*SPEED-8.6) C=DEXP(-0.5-7.1»!SPEED**2.32)) E=EMAX+0.OO780OG780O EFFCY = E-B*((PRAT-1 . )* *(-2.4))-C*(1.-DEXP(-(PRAT-1.)/2.)) A = 2. 1 1+4.25*! ( 1 .0-SPEEO ) • *2 ) MASS-1 001782-DEXP!-A*(PRAT-1.0)) RETURN END  C C C PART 3 C C///////////////////// C/// STEAM //// C// THERMODYNAMICS /// C///////////////////// C C C/////////// C///VATS//// C//T.S-VAP// C/////////// SUBROUTINE VATS(P.T,H.S.CP.X,HTC,VSI) REAL'S P,T,S.H.CP.P1.S1.X.HTC,VSI X-1.0 P1=DEXP((7.76622-S+2.17*DL0G((T+273.15)/773.15))/0.4581) 10 L = 2 CALL STEAM(P1.T.H.S1,CP,HTC,VSI,L) P = P1*DEXP((S1-S)/0.4581) IF (DABS((P-P1)/P).LT.0.001)RETURN P1-P GOTO 10 END C C/////////// C///VATH//// C//T.H-VAP// C/////////// SUBROUTINE VATH(P , T .H, S.CP , X .HTC . VSI ) REAL'S P.T.H.S,PMIN,P1,P2,CP,H1,H2,HTC,VSI,S1,S2,X X-1.0 IF(T.GT.375) GOTO 13 CALL PSAT(PMIN.T) 9 P1-PMIN-1.1 10 P2=P1+1.0 L-2 CALL STEAM! P2 , T , H2 .S2.CP.HTC.VSI ,L) L*2 CALL STEAM1P1.T.H1.S.CP.HTC.VSI.L) P=(H*(P1-P2)+P2'H1-P1*H2)/IH1-H2) IF(DABS((P-P1)/P).LT.0.0OO1) RETURN P1=P GOTO 10 13 PMIN=22.10 GOTO 9 END C C///////////// C///SATCON////  —. CTi  599  C///P.T-SAT///  600  C/11/1////11/1  601 602 603 604 605 606 607 608 609 610 611 612  C C/////////// C///TSAT//// C///P-SAT///  614 615 616 617 618 619 620 621 622 623 624 625 626 627 628 629 630 631 632 633 634 635 636 637 638 639 640 641 642 643 644 645 646 647 648 649 650 651 652 653  SUBROUTINE TSAT(P.TSA) REAL'S P.T.P1.T1,DPDT,TC.TA.PC,A,B.C,TSA.TAU TSA=175'(P"0.246) LZT-1 GOTO 14 C/////////// C///PSAT//// C///T-SAT/// C//////////V ENTRY PSAT(P.TSA) LZT-0 14 T-TSA+273.15 TC"647.25 PC»22.093 TAU-<I-I1/TC)) A-(-7.863889'TAU)+<1.898527'<TAU" 1.5)) B=(-2. 364891 • ( T A U " 2'. 5) ) + (-9 .9114 14'(TAU"6 . 5 ) ) C-(9.982952*(TAU"7.5))+A+B P1«PC*DEXP((TC/T)'C) IF (LZT.EO.O)GOTO 16 TA-T DPOT«(-P1/TA)'(DL0G(P1/PC)+(-7. 86+2 .84'< TAU"0. 5 ) - - 5 . 9 1 » ( T A U " 1 .5)-64 . 4*( T A U " 5 .5)+74 . 87'(TAU"6 . 5 ) ) TWSA TSA=TSA+((P-P1)/DPDT) IF (DABS(TSA-TI).LT.O.OI)RETURN GOTO 14 16 P = P1 RETURN END C C///////////// C///STATES//// C/////P.S///// C///////////// SUBROUTINE STATES(P.T.H.S.CP.X.HTC.VSI) REAL'S P,T.H.S.X.TST,HF.HG.SF.SG.CP.HTC.VSI,T1,S1 CALL TSAT(P.TST) CALL SATCON(P.TST.HF.HG.SF.SG) IF(S.LE,SG)GOTO 100  613  SUBROUTINE S/UC0N1 P. T . HF . HG, SF , SG) REAL'S P.T.HF,HG.SF,SG,CP,HTC,VSI L=2 CALL STEAM(P,T,HG,SG.CP,HTC.VSl ,L) L=3 CALL STEAM(P,T,HF,SF,CP,HTC,VSI.L) RETURN END  C////I////II  654  0.111111111111  657  ZIIIUIIIIIII  655 656 658  C///INTES//// C//P.S-VAP///  ENTRY INT ESIP.T.H.S.CP.X,HTC.VSI )  659 660 661 662 663 664 665 666 667 668 669 670 67 1 672 673 674. 675 676 677 678 679 680 681 6B2 683 684 685 686 687 688 689 690 691 692 693 694 695 696 697 698 699 700 701 702 703 704 705 706 707 708 709 710 711 7 12 713 714 715 716 717 718  X=1.0 T1=773.15'0EXP((S-7.76622+(O.4581'0L0G<P)))/2.17)-273.15 10 L=2 CALL STEAM(P,T1.H.S1,CP.HTC.VSI.L) T=(T1+273.15)'OEXP((S-S1)/2.17)-273.15 IF (DABStT-TI).LT.0.01)RETURN T1=T GOTO 10 1O0 IF (S.LE.SF)GOTO 101 T-TST X=(S-SF)/(SG-SF) H=HF + X *(HG-HF) CP-1000000.0 RETURN 101 CONTINUE C/////////// C///LIOS//// C//P.S-LIO// C/////////// ENTRY LIOS(P,T,H.S,CP.X,HTC.VSI) X=0 O T1=273. 15'0EXP(S/4.18)-273. 15 CALL TSAT(P.T) IF (T1.GT.T) T1=T 13 L=3 CALL STEAM(P.T1.H.S1.CP.HTC,VSI.L) T=(T1+273.15)«DEXP((S-S1)/4.18)-273.15 IF (DABS(T-T1).LT.0.01)RETURN T1-T GOTO 13 END C C///////////// C///STATEH//// C/////P.H///// C/////////7/// SUBROUTINE STATEH(P.T.H.S.CP,X,HTC,VSI) REAL'S P.T,H.S,X.TST,HF.HG.SF,CP,SG,HTC.VSI.H1,T1 CALL TSAT(P.TST) CALL SATCON(P.TST.HF.HG.SF.SG) IF(H.L E.HG)GOTO 102 C//////////// C///INTEH//// C//P,H-VAP/// C//////////// ENTRY rNTEH(P,T.H.S.CP,X,rfTC.VSI) X=1.0 T1=500+((H-3478)/2.17) 11 L=2 CALL STEAM(P.T1.H1,S.CP.HTC,VSI,L) T=T1+((H-H1)/2 17) IF (0A8S(T-T1).LT.0.01)RETURN T1=T GOTO 11 102 IF (H.LE HF(GOTO 103 T=TST X=(H-HF)/(HG-HF) S=SF+X'(5G-SF) CP=100O000.0 RETURN  rr\ rn  7 19 7 20 721 722 723 724 725 726 727 728 729 730 731 732 733 734 735 736 737 738 739 740 74 1 742 743 744 745 746 747 748 749 750 751 752 753 754 755 756 757 758 759 760 761 762 763 764 765 766 767 768 769 770 77 1 772 773 774 775 776 777 778  103 CONTINUE Clllllll/lll C///LIQH//// C//P.H-HO//  ClllIII  II III  ENTRY LIQHlP.T.H.S.CP.X.HTC.VSI) X-0.0 T1=H/5.0 12 L*3 CALL STEAMIP,T1,H1.S.CP.HTC,VSI.L) T-T1 + UH-HD/4.18) IF (DABS(T-TI).LT.O.OI)RETURN T 1 =T GOTO 12 END  C Zlllllllllll/I ClIISTAlElllll  cllllP.nilill  Clllllllllllll SUBROUTINE STATET(P.THETA,H.S,CP,X.HTC.VSI) IMPLICIT REAL'S (A-H.O-Z) REAL*B MASS.MU,W(5,5).KT C INTEGER TYPE C COMMON /AREA2/ VEL,RHO.AREA,OIAM,MU,KT.PR,REY.EPS.TYPE C IF (THETA.GE.374.3) GOTO 925 CALL TSAT(P.TST) IF(THETA.LT.TST)GOTO 201 C 925 L-2 X- 1 .0 GOTO 202 C 201 L-3 X-0.00 202 CONTINUE Clllllll/llll C///STEAM//// C///P.T-L//// Cllllllllllll ENTRY STEAM (P.THETA.H.S,CP.HTC.VSI.L) C C L-1 INIT. L»2 VAP GIVEN PST, L-3 LIO GIVEN P&T, L-4 GIVEN VS7 C C UNITS; P-MPA THETA-DEG C IPTS68 V-CC/GM H-KJ/KG C S.CP,CV-Kd/KG/DEG K RH0-KG/M**3 C VISC-KG/M/S KT-KW/M/OEG K C REAL*8 KT1,KT2,KT3,KTA,KTB.KTC,TM(5),RM(5) -.MUA.MU0.MU1,MU2.MU3,MU4,MU5,KTO,C(10,10) C R-0.46151 GO TO (1.12.12,12,12),L C 12 CONTINUE TEMP-273.15+THETA RT-R-TEMP  779 780 78 1 782 783 784 785 786 787 788 789 790 791 792 793 794 795 796 797 798 799 800 801 802 803 804 805 806 807 808 809 810 81 1 812 8 13 8 14 815 816 8 17 818 8 19 820 821 822 823 824 825 826 827 828 829 830 831 832 833 834 835 836 837 838  C C C C  TAU=1000./TEMP TA=OLOG(TEMP) 5ZER0-.001«(3229.12+(-838.93)/TAU+109.9947/TAU*«2 + (-82.2064) -/TAU««3+24 . 26165/TAU**4+(- 101 1 . 249 )*TA-1011 . 249 )+46 .O/TEMP HZERO-1857.065*419.465/(TAU**2)-73.3298/(TAU«*3)+61.6548/ -(TAU**4)-19.4093/(TAU*»5)+46.0»(TA-1.0)+1.472759+TEMP CPZER0-0.83893/TAU-0.2199894/(TAU**2)+0.2466192/<TAU**3) - -0. 0970466/ ( TAU* *4 )+46 . 0/TEMP+ 1 . 472759  GO TO ( 1 .2.3,4),L C C * * * • READ DATA *»*• C 1 E-4 . 8 DO 102 J - l , 7 READ15.103) ( C ( I . d ) , 1 - 1 . 5 ) READI5.103) ( C ( I , J ) . I - 6 . 1 0 ) 103 F0RMAT(5F13.8) 102 CONTINUE RETURN C C L-2 C 2 RHO-P/RT DRHO-RHO*.1 25 JUMP-0 RMAX-. 1 GOTO 19 18 PCALC=RHO*RT*(1.+W(1.1)+W(2.1)) 20 PC 1-PCALC JUMP-JUMP+1 IF (JUMP-10) 31.31.32 32 RMAX-RMAX*.5 31 CONTINUE RH1-RH0 RHO-RH1+DRHO 19 DO 104 1-1,5 DO 104 J-1,5 104 W(I,J)=0.0 C C * * SHORT VERSION W11.W12.W21 ONLY** C 120 RMC-RH0-O.634 TMC-TAU-1.544912 T2S-TAU-2.5 EXPE-DEXP(-E'RHO) RONE-RHO-1.0 DO 144 J-2,7 AB-O. AC-O. DO 141 1=2,4 AA=C(I.J)*RONE**(1-2) AB-AB + AA *RONE 141 AC-AC + AA* ( I - 1 ) AA=EXPE*(C(9.J)+RHO*C(10,J)) AB«AB+AA+C(1,d) AC-AC*EXPE*C(10.J)- E *AA  839 840 84 1 842 843 844 845 846 847 848 849 850 851 852 853 854 855 856 857 858 859 860 B61 862 863 864 865 866 867 868 869 870 871 872 873 874 875 876 877 878 879 880 881 882 883 884 885 886 B87 888 889 890 891 892 893 894 895 896 897 898  AA = T 2 5 « M 0 - 2 ) W( 1, 1)=w(1, 1 )+AB*AA W(2,1)=W< 2. 1 1 + AC'AA 144 W(1,2)=W(1,2)*AB*AA«(1.+TMC*(0-2)/T25) DO 142 1=5,8 AA=C(I,2)*RONE*»(I-2) W(1,1)-W(1,1)+AA*RONE W(1,2)-W(1,2)+AA«R0NE 142 W(2,1)=W(2.1)*AA»<1-1) W(1.1)=W(1, 1 )'TMC W(2,1)=W(2.1)»TMC DO 143 1=2.8 AA-CU, 1)«RMC**(I-2) W(1,1)=w(1,1)+AA*RMC 143 W(2.1>»W(2.1)+AA'(1-1) AA-EXPE'(C(9.1)+RHO'C(10.1)) W(1,1)=w(1,1)+C(1.1)+AA W(2.1)=W(2,1)+EXPE«C(10.1)- E *AA W( 1.1)=W(1.1)«RHO W(2.1)=W(2,1)»RH0*"2 W(1,2)-W(1,2)«RH0*TAU C  27 26 22 33  IF(OUMP.EQ.O) GOTO 18 PCALC=RHO*RT«(1.+W(1.1)+W(2,1) ) DRHO-(P-PCALC)/(PCI-PCALC)*(RH1-RH0) IF (DABS(DRHO)-RMAX) 26.26.27 DRHO-RMAX*DRHO/DABS(DRHO) IF <0UMP-2O)22,42,42 IF (DABS(DRHO)-.1E-6*RH0) 60.60.33 IF(DABS(P-PCALC)-1 E-5*P) 60,60,20  C C L-3 C V-.97+.032*(,01*THETA)--2 3 RHO-1./V DRHO-1./(V+.01+.005M,01«THETA)*-2) -RHO GO TO 25 C V-1./RHO 60 C C L-4 C 4 RHO-1 ./V C 00 101 1-1.5 DO 101 d-1.5 101 W(I.0)=0. C C •• LONG VERSION USING GRST ALL W OR OS  c  121 DO 111 J-1,7 TM(1)=1 203 IF (0-2) 230.231,232 232 TM( 1)=EXPK(TAU-2.5.J-2) 23 1 TM( 1 ) = TM( 1 )«(TAU-1.544912) 230 CONTINUE C 6 TM(2)-1 206 IF (0-2) 261.260.262 261 TM(2)=0.0  899 900 901 902 903 904 905 906 907 908 909 910 91 1 912 913 914 915 916 917 918 919 920 921 922 923 924 925 926 927 928 929 930 931 932 933 934 935 936 937 938 939 940 94 1 942 94 3 944 945 946 947 948 949 950 95 1 952 953 954 955 956 957 958  GOTO 260 262 TM(2 1=(TAU-1544912)»EXPK(TAU-2.5,d-3)«<0 -2) -+EXPKITAU-2.5,0-2) 260 CONTINUE C 9 TM(3)-1 IF (0-3) 209.292.291 209 TM(3)-0.0 GOTO 290 291 TM(3)-(TAU-1.544912)*(0-2)•(0-3)*EXPK(TAU -2.5.0-4) •*2. «(d-2)-EXPK(TAU-2.5.0-3) GOTO 290 292 TM(3)=2.0 290 CONTINUE C DO 111 1-1.10 c 4 RM(1)-1.0 LD-0 LDA-1 IF (1-9) 240.241.241 240 IFIO.EO.1) RM(1)-EXPK(RHO-0.634,1-1-LD) IF(O.NE.1) RM(1)-EXPK(RHO-1.0,1-1-LD) GOTO 249 241 IA-I-8 DRHO-RHO EXPE-DEXP(-E-RHO) RM(1)=EXPE»EXPK(DRHO.IA-1) 249 CONTINUE c 5 RM(2)-1.0 5 LD-1 IF (1-9) 250.251,251 250 IF(J.EO.1) RM(2)-EXPK(RHO-0.634,1-1-LD) IFIO.NE.1) RM(2)«EXPK(RH0-1.0,1-1-LD) RM(2)-RM(2)*(I-1) GOTO 259 251 IA-I-8 DRHO-RHO EXPE=DEXP(-E*RHO) RM(2)=EXPE«(IA-1)«EXPK(ORHO.IA-2) -E'EXPE •EXPMORHO. IA 259 CONTINUE c 7 123 RM(3)=1.0 LD-2 IF (1-9) 270.271.271 270 1F(O.EO.1) RM(3)-EXPK(RHO-0.634,I- 1-LD) IF(d.NE.1) RM(3)=EXPK(RH0-1.0,1-1-LD) RM(3)-RM(3)-(1-2) RM(3)-RM(3)*(I-1) GOTO 279 271 IA-1-8 DRHO-RHO EXPE-DEXP( - E*RHO) RM(3) = EXPE-(I A-1)*(IA-2)»EXPK(DRH0.IA-3) •-2.-E'EXPE'lIA-1)*EXPK(DRHO.IA-2) •+E*»2*EXPE*EXPK(0RH0.IA-1) 279 CONTINUE 8 c RM(4)-1.0  o  959  LD = 3 LDA = 4 IF ( 1 - 9 ) 280.281.281 280 IF(d.EO.1) RM(4) = EXPK(RHO-0.634,I - 1-LD) I F ( J . N E . 1 ) RM<4)=EXPK(RH0-1.0.I-1-LD) RM(4)=RM(4)•( 1-3) RM(4)-RM(4)*(1-2) RM(4)=RM(4)•(1-1) GOTO 289 281 IA=I-8 DRHO=RHO EXPE=DEXP(-E*Rlin) RM(4)=EXPE«(IA-3)*<IA-2)*<IA-1)*EXPK(DRHO,IA-4) --3.*E*EXPE'(IA-1)*<IA-2)*EXPK(DRHO,IA-3) -+E**2*EXPE*£XPK(DRH0.IA-2) + E* *3*EXPE*EXPK(DRH0,IA-1) 289 CONTINUE 122 DO 111 K=1 .4 DO 119 L-1,3 W(K.L)=W(K.L)+C(I.d)*RM(K)*TM(L) 1 19 CONTINUE 1 1 1CONTINUE  9G0 96 1  962 963 964 965 966 967 968 969 970 97 1 972 973 974 975 976 977 978 979 980 981 982 983 984 985 986  C 135 DO 112 KM. 4 DO 112 LM.3 112 W(K,L)"W(K.L)*RH0**K*TAU**(L-1) 140 CONTINUE C IF (RHO .LT. 0.0) WRITE(9.43) P.THETA,RHO.DRHO.L IF (RHO .LT. 0.0) RETURN  987  988 989 990 991 992 993 994  C P=RH0*RT*(1.+W(1,1)+W(2.1)) H=HZERO+RT*(W(1.1)+W(2,1)+W(1,2)) S--SZERO-R»(W<1.1)-W(1,2>+0L0G(RH0)> C C C  995  996 997 998 999 1000 1001 1002 1003 1004 1005 1006 1007 1008 1009 1010 101 1 1012 1013 1014 1015  1016 1017 1018  C C C  OHVT » OH/DV AT CONSTANT T, SIMILARLY FOR DPTV AND DPVT DHTV=CPZER0+R*(W( 1, 1) + W(2,1)-W(1.2)-W(2,2)-W( 1 , 3 ) ) DHVT=-RHO*RT*(W(1,1)+3.*W<2,1)+W(3.1)+W<1.2)+W(2,2)) DPTV=RHO*R«(1.+W(1.1)+W(2,1)-W(1,2)-W(2,2)) 0PVT = -RH0"2*RT*( 1.+2.*W(1,1)+4.*W(2.1)+W( 3,1)) CV-DHTV-DPTV/RHO CP»DHTV-DHVT«DPTV/DPVT DENS=RHO*10O0.0 RHO=RHO* 1000.0 CALCULATE THERMAL CONDUCTIVITY  KT  TAW=(THETA+273.15)/647.27 RHR=DENS/317.763 KT0=0ABS(TAW-1.0)+0.00308976 IF(TAW.GE.1.0) KT1=KT0**(-1.0) IF(TAW.LT.1.0) KT1"10.0932*(KT0**(-0.6)) KT2=2.0*0.0822994«KTO**(-0.6) KT3=KT2+1.0 KTA=DSQRT(TAW)*(0.0102811+0.0299621*TAW+0.0156146*TAW**2 -0.00422464*TAW«*3) KTB=-0.39707+0.400302*RHR+1.06*DEXP(-0.171587*((RHR+2.39219) •*2) ) KTC=(0.0701309/TAW* * 10.0+0.011852)*RHR*«1.8*DEXP(0.642857* (1.O-RHR••2.8))«0.O0l69937*KT1'RHR*•KT2*DEXP(KT2/KT3*  1019 1020 102 1 1022 1023 1024 1025 1026 1027 1028 1029 1030 1031 1032 1033 1034 1035 1036 1037 1038 1039 1040 104 1 1042 1043 1044 1045 1046 1047 1048 1049 1050 1050.5 105 1 1052 1053 1054 1055 1056 1057 1058 1059 1060 1061 1062 1063 1064 1065 1066 1067 1068 1069 1070 107 1 1072 1073 1074 1075 1076 1077-  -( 1 0-RHR«'KT3) )-1 02*DEXP(-4.11717*TAW**1.5-6. 17937/RHR**5 KT=KTA+KTB+KTC C C CALCULATE VISCOSITY VISC  c  RH1=RHR-1.0 TA1=1 O/TAW-1.0 MUA=DSORT(TAW)/(0.0181583+0.0177624/TAW+0.0105287/TAW* --0.003G744/TAW*«3) MUO-O.501938+0.235622*RH1-0.274637*RH1**2+0.145831*RH1 --0.0270448*RH1*»4 MU1=TA1*(0.162B88+0.789393*RH1-0.743539*RH1**2 -+0.263129*RHI*«3-0.0253093*RH1**4) MU2=TAl**2*(-0.130356+0.673665*RH1-0.959456*RH1**2 -+0.347247*RH1*«3-O.02677S8*RH1**4) MU3-TA1**3*(0.907919+1.207552*RH1-0.687343+RH1**2 -+0.2134B6*RH1**3-0.O822904*RH1**4) MU4=TA1**4*(-0.551119+0.067O665*RH1-0.497089*RH1**2 -+0.100754«RH1«*3+0.0602253*RH1**4) MU5=TA1«*5*(0.146543-0.0843370*RH1+0.195286«RH1«*2 --0.032932*RH1«*3-0.0202S95*RH1**4) MU=MUA"DEXP(RHR*(MUO+MU1+MU2+MU3+MU4+MU5))* 1E-6  c  c c  c c c  *2 •*3  PR=MU*CP/KT*1000.0 REY=RHO*VEL*DIAM/MU IF(TYPE.EO.I) HTC-0.023*KT/DIAM*(REY**0.8)*(PR**0.33) IF(TYPE.E0.2) HTC"0.33*KT/DIAM*(PEY**0.6)*(PR**0.3) IF (THETA.LE.374.14) THA«DSQRT((374.14-THETA)/100.0) IF(TYPE.E0.4) HTC»O.O33*KT/0lAM*(REY**O.87)*(PR**O.4)*DEXP -(1 0429*THA-0.2B24*(THA**2)-O.OO115*(THA**3)+O.1437*(THA**. V S I M .0 WRITE(4.420) P,THETA,RHO.VEL,PR,REV,HTC.VSI TEMP DENSITY VELCTY ', 420 FORMAT!' PRESS -'PRANDL* REYNOLDS* VISCOSITY KT HTC VSI'/ -.F7.4.F7.1,F10.3,F8.1.FB.4,' '.E12.4,' '.F10.7, -F10.5.F8.1.F8.3///) REYNOLDS ' 319 FORMAT(' VISCOSITY COND-K DIAM MASS PR -,'H.T.COEF P.COEF TYPE'/,F10.7,F7.4,F6.3,F6.2.F6.3.' ',E9 -' '.E9.3.' '.F8.5.I3//) RETURN NONCONVE RGENCE 42 43  c c c  * • 4 *«EXPK  1 2 3  STATEMENT  WRITE(9,43)P,THETA.RHO.DRHO.L NE0=1 GO TO 60 FORMAT ('NO CONVERGENCE P,T,RHO,DRHO-'/.4F20.5.15) END FUNCTION****  DOUBLE PRECISION FUNCTION EXPK (A.L) REAL'S A IF ( L ) 1.2,3 EXPK=0. RETURN RETURN EXPK=A-«L E  X  P  K  =  1078 ,  1  0  E  n  d  o  f  7  RETURN END  9  f  )  l  8  

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